This Preliminary Official Statement and the information contained herein are subject to completion or amendment. These securities may not be sold nor may offers to buy be accepted prior to the time

the Official Statement is delivered in final form. Under no circumstances shall this Preliminary Official Statement constitute an offer to sell or the solicitation of an offer to buy nor shall there be any sale

of these securities in any jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such jurisdiction.

PRELIMINARY OFFICIAL STATEMENT DATED APRIL 3, 2014 

NEW ISSUE -- Book Entry

In the opinion of Bond Counsel, assuming continued compliance by the Authority with certain covenants, interest on the 2014M1 

Bonds is excludable from gross income for federal income tax purposes under existing statutes, regulations and judicial decisions. Interest on

the 2014M1 Bonds is not an item of tax preference in computing the alternative minimum taxable income of individuals or corporations. Interest

on the 2014M1 Bonds will, however, be included in the computation of certain taxes including alternative minimum tax for corporations. See

“TAX MATTERS” for a description of certain other federal income tax consequences to certain recipients of interest on the 2014M1 Bonds.

The 2014M1 Bonds and the interest thereon will be exempt from all State, county, municipal and school district and other taxes or assessments

imposed within the State of South Carolina, except estate, transfer and certain franchise taxes.

$,000

South Carolina Public Service Authority

Revenue Obligations, 2014 Series M1

Consisting of

$,000 1.75% Current Interest Bearing Bonds Due January 1, 2019

$,000 3.00% Current Interest Bearing Bonds Due January 1, 2024

$,000 4.00% Current Interest Bearing Bonds Due January 1, 2029

$,000 4.30% Current Interest Bearing Bonds Due January 1, 2034

$,000 3.00% Capital Appreciation Bonds Due January 1, 2023

$,000 4.00% Capital Appreciation Bonds Due January 1, 2028

$,000 4.30% Capital Appreciation Bonds Due January 1, 2033

Dated: May 1, 2014 

The Revenue Obligations, 2014 Series M1 (the “2014M1 Bonds”) will be sold directly by the South Carolina Public

Service Authority (the “Authority”) only to residents of the State of South Carolina (the “State”), customers of the Authority,

members of electric cooperatives organized and existing under the laws of the State, and electric customers of the Bamberg Board

of Public Works, South Carolina and the City of Georgetown, South Carolina.

The Current Interest Bearing Bonds will be issued in registered form in denominations of $500 or integral multiples

thereof. The Capital Appreciation Bonds will be issued in registered form in denominations of $200 original principal amount or

integral multiples thereof. The 2014M1 Bonds will be sold by the Authority directly to investors. The maximum amount of

2014M1 Bonds, as measured by the initial purchase price thereof, which may be initially purchased by one investor shall be

$50,000 as described herein. Any 2014M1 Bonds will be purchased by the Authority on demand by the owner thereof upon the

terms and conditions set forth herein. The Authority’s obligation to redeem the 2014M1 Bonds at the election of the Bondholders

is limited to 5% of the original issue amount of the 2014M1 Bonds in any calendar year. Redemptions will also be limited on a

monthly basis to one-twelfth of the 5% annual maximum. Interest on the Current Interest Bearing Bonds, payable on January 1

and July 1 of each year, commencing January 1, 2015 (240 days of interest), interest on the Capital Appreciation Bonds

(compounded semiannually and payable only upon maturity or earlier redemption or elective purchase thereof), maturing principal

of the Current Interest Bearing Bonds and maturing principal of the Capital Appreciation Bonds will be payable by check or draft

mailed to the registered owners thereof by The Bank of New York Mellon Trust Company, N.A. (the “Trustee”).

The 2014M1 Bonds will be subject to redemption prior to maturity at the option of the Authority on and after January 1,

2015, as set forth herein.

The 2014M1 Bonds are payable solely from, and secured by a lien upon and pledge of, the Revenues and moneys in the

Revenue Fund of the Authority on a parity with the lien and pledge securing Revenue Obligations heretofore and hereafter issued

pursuant to the Revenue Obligation Resolution.

The 2014M1 Bonds are being issued to fund a portion of the cost of the Authority’s ongoing capital improvement program.

The 2014M1 Bonds are not debts of the State, nor of any political subdivision thereof, and neither the State nor

any of its political subdivisions shall be liable thereon, nor shall they be payable from any funds other than the Revenues

of the Authority pledged to the payment thereof.

The 2014M1 Bonds are offered when, as and if issued subject to the approval of legality by Haynsworth Sinkler Boyd,

P.A., Charleston, South Carolina, Bond Counsel. 

May _, 2014 
[THIS PAGE INTENTIONALLY LEFT BLANK]
SOUTH CAROLINA PUBLIC SERVICE AUTHORITY

One Riverwood Drive

Moncks Corner, South Carolina 29461

(843) 761-8000

ADVISORY BOARD

Governor NIKKI HALEY

Attorney General ALAN WILSON

State Treasurer CURTIS M. LOFTIS, JR.

Comptroller General RICHARD ECKSTROM

Secretary of State MARK HAMMOND

DIRECTORS 

W. LEIGHTON LORD, III, Chairman J. CALHOUN LAND, IV

WILLIAM A. FINN, First Vice Chairman PEGGY H. PINNELL

BARRY D. WYNN, Second Vice Chairman DAVID F. SINGLETON

KRISTOFER CLARK CECIL E. VIVERETTE

EXECUTIVE MANAGEMENT

LONNIE N. CARTER ................................................... PRESIDENT AND 

CHIEF EXECUTIVE OFFICER

JAMES E. BROGDON, JR. ............................................... EXECUTIVE VICE PRESIDENT AND

GENERAL COUNSEL

RENNIE M. SINGLETARY, III . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . EXECUTIVE VICE PRESIDENT,

CORPORATE SERVICES

JEFFREY D. ARMFIELD ................................................ SENIOR VICE PRESIDENT AND CHIEF

FINANCIAL OFFICER

ROBERT B. FLEMING, JR. .............................................. SENIOR VICE PRESIDENT,

POWER DELIVERY

L. PHIL PIERCE ...................................................... SENIOR VICE PRESIDENT,

GENERATION

MARC R. TYE ....................................................... SENIOR VICE PRESIDENT,

CUSTOMER SERVICE

TRUSTEE

The Bank of New York Mellon Trust Company, N.A. Jacksonville, Florida

BOND COUNSEL

Haynsworth Sinkler Boyd, P.A. Charleston, South Carolina

FINANCIAL ADVISOR

Public Financial Management, Inc. Charlotte, North Carolina
No dealer, broker, salesman or other person has been authorized by the Authority or the Underwriter to give any

information or to make any representations with respect to the 2014M1 Bonds other than the information and

representations contained in this Official Statement, and, if given or made, such other information or representations may

not be relied upon as having been authorized by the Authority. This Official Statement does not constitute an offer to sell

or the solicitation of an offer to buy nor shall there be any sale of the 2014M1 Bonds by any person in any jurisdiction in

which it is unlawful for such person to make such offer, solicitation or sale. The information set forth herein has been

provided by the Authority and other sources which are believed to be reliable. The information and expressions of opinion

herein are subject to change without notice and neither the delivery of this Official Statement nor any sale made hereunder

shall, under any circumstances, create any implication that there has been no change in the matters described herein since

the date hereof.

NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES

COMMISSION HAS APPROVED OR DISAPPROVED OF THE 2014M1 BONDS OR PASSED UPON THE ADEQUACY

OR ACCURACY OF THIS OFFICIAL STATEMENT. ANY REPRESENTATION TO THE CONTRARY IS A

CRIMINAL OFFENSE.

TABLE OF CONTENTS

INTRODUCTION ..................................................................... 1

 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

 The Authority . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

 Authorization of 2014M1 Bonds ......................................................... 1

 Indebtedness of the Authority . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

 Purpose of the 2014M1 Bonds ........................................................... 2

DESCRIPTION OF THE CURRENT INTEREST BEARING BONDS ............................ 2

 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

 Redemption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

 Purchase of Current Interest Bearing Bonds by Authority ...................................... 3

DESCRIPTION OF THE CAPITAL APPRECIATION BONDS ................................. 3

 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

 Redemption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

 Purchase of Capital Appreciation Bonds by Authority ........................................ 4

 Accreted Value Table for Bonds Maturity January 1, 2023 ..................................... 5

 Accreted Value Table for Bonds Maturity January 1, 2028 ..................................... 6

 Accreted Value Table for Bonds Maturity January 1, 2033 ..................................... 8

DESCRIPTION OF THE BOOK ENTRY ONLY SYSTEM .................................... 9

LONG-TERM CAPITAL STRUCTURE PLAN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

FINANCING PLAN FOR SUMMER NUCLEAR UNITS 2 AND 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

DEBT SERVICE SCHEDULE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

SECURITY FOR THE 2014M1 BONDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

 Rate Covenant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

 Additional Indebtedness . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

 Capital Improvement Fund Requirement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

ORGANIZATION AND MANAGEMENT OF THE AUTHORITY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

 

CUSTOMER BASE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

 Service Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

 Wholesale - Central . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

 Wholesale - Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

 Direct Retail Service Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

 Large Industrial Contracts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

i
RATES AND RATE COMPARISON . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

 Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

 Rate Comparison . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

POWER SUPPLY AND POWER MARKETING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

 Existing Generating Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

 Existing Power Resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

 Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

 Interconnections and Interchanges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

 Reliability Agreements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

 Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

 General Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24

 Fuel Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

 The Energy Authority . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

 Colectric Partners . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

CAPITAL IMPROVEMENT PROGRAM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

 General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

 Long-Term Power Supply Plan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

 Summer Nuclear Units 2 and 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

HISTORICAL SALES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

 Historical Demand, Sales and Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

FINANCIAL INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

 Historical Operating Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

REGULATORY MATTERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

 The Electric Utility Industry Generally . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

 Environmental Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

 FERC Hydro Licensing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

 NERC Regulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

 Nuclear Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

LITIGATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38

FINANCIAL ADVISOR . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

TAX MATTERS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

 The 2014M1 Bonds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 39

 State Tax Exemption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

APPROVAL OF LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

MISCELLANEOUS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

APPENDICES

COMPANY’S FINANCIAL STATEMENTS ................................................I

SUMMARY OF CERTAIN PROVISIONS OF THE REVENUE 

 OBLIGATION RESOLUTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II

FORM OF OPINION OF HAYNSWORTH SINKLER BOYD, P.A. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . III

ii
[THIS PAGE INTENTIONALLY LEFT BLANK]

iii
OFFICIAL STATEMENT

relating to

$,000

South Carolina Public Service Authority

Revenue Obligations, 2014 Series M1

$,000 1.75% Current Interest Bearing Bonds Due January 1, 2019

$,000 3.00% Current Interest Bearing Bonds Due January 1, 2024

$,000 4.00% Current Interest Bearing Bonds Due January 1, 2029

$,000 4.30% Current Interest Bearing Bonds Due January 1, 2034

$,000 3.00% Capital Appreciation Bonds Due January 1, 2023

$,000 4.00% Capital Appreciation Bonds Due January 1, 2028

$,000 4.30% Capital Appreciation Bonds Due January 1, 2033

INTRODUCTION

General

The purpose of this Official Statement is to set forth information concerning the South Carolina Public

Service Authority (the “Authority”) Revenue Obligations, 2014 Series M1 (the “2014M1 Bonds”), offered hereby.

The summary of the Revenue Obligation Resolution (hereinafter defined) herein contained is made subject

to all of the provisions of such document, and such summary does not purport to be complete statements of such

provisions. Reference is hereby made to such document for further information in connection therewith. Copies

of such document may be examined at the main office of the Authority in Moncks Corner, South Carolina, and at

the office of Haynsworth Sinkler Boyd, P.A., Charleston, South Carolina. The REPORT OF THE COMPANY’S

FINANCIAL STATEMENTS is attached as Appendix I to this Official Statement.

Defined terms not herein defined are defined in Appendix II -- “SUMMARY OF CERTAIN

PROVISIONS OF THE REVENUE OBLIGATION RESOLUTION.”

The Authority

The Authority is a body corporate and politic created by Act No. 887 of the Acts of the State of South

Carolina (the “State”) for 1934 and acts supplemental thereto and amendatory thereof (Code of Laws of South

Carolina 1976, as amended -- Sections 58-31-10 through 58-31-450) (the “Act”), which, among other things,

authorizes the Authority to produce, distribute and sell electric power and to acquire, treat, transmit, distribute and

sell water at wholesale within the counties of Berkeley, Calhoun, Charleston, Clarendon, Colleton, Dorchester,

Orangeburg and Sumter, South Carolina. The Authority owns and operates the Lake Moultrie Regional Water

System and the Lake Marion Regional Water System. Under current State law and by contract, each of the regional

water systems is required to be self supporting. The Authority began electric power operations in 1942. The

commercial operation of the regional water system began in October 1994.

Authorization of 2014M1 Bonds

The 2014M1 Bonds are issued pursuant to a resolution adopted by the Authority's Board of Directors on

April 26, 1999, as amended and supplemented from time to time (the “Revenue Obligation Resolution”). The

2014M1 Bonds now being offered and all obligations heretofore and hereafter issued pursuant to the Revenue

Obligation Resolution (collectively, the “Revenue Obligations”) are on a parity with each other. The Revenue

Obligations are secured by a lien upon and pledge of the Revenue Fund and the revenues of the Authority's System

and other moneys paid into the Revenue Fund (the “Revenues”). See “SECURITY FOR THE 2014M1 BONDS.” 

By supplemental resolution duly adopted, the Authority authorized the issuance of the 2014M1 Bonds.

Indebtedness of the Authority

Revenue Obligations. Pursuant to the Act, the Board of Directors of the Authority adopted the Revenue

Obligation Resolution providing for the issuance of the Authority’s Revenue Obligations. As of February 28,

2014 there was outstanding approximately $6,308,648,000 aggregate principal amount of Revenue Obligations. 

1
Commercial Paper Notes and Leases. In addition, the Authority has issued indebtedness evidenced by

commercial paper notes (the “Commercial Paper Notes”) and leases. As of February 28, 2014 there was

outstanding $372,073,000 of Commercial Paper Notes and approximately $156,000 aggregate amount of leases.

The lien and pledge of Revenues securing such Commercial Paper Notes and leases is junior to that securing the

Revenue Obligations. 

The Board of Directors of the Authority has by resolution authorized the issuance of Commercial Paper

Notes not to exceed the lesser of (i) 20% of the aggregate Authority debt outstanding as of the last day of the most

recent fiscal year for which audited financial statements of the Authority are available or (ii) the aggregate unused

commitment of the Banks (hereinafter defined) (i.e., the commitment minus any loans outstanding under the

revolving credit agreements) under any revolving credit agreements the Authority may enter into to obtain funds

to repay the Commercial Paper Notes. The Commercial Paper Notes are secured by a lien upon and pledge of

Revenues junior to the lien and pledge securing (i) Revenue Obligations, (ii) expenses of operating and maintaining

the System, and (iii) payments into the Lease Fund, but prior to the payments into the Capital Improvement Fund. 

To obtain funds, if needed to repay the Commercial Paper Notes, the Authority has entered into Revolving

Credit Agreements (the “Revolving Credit Agreements”) with U.S. Bank National Association, Wells Fargo Bank,

National Association, JP Morgan Chase Bank, National Association, TD Bank, N.A. and Barclays Bank PLC

(collectively, the “Banks”) for an aggregate amount of $800,000,000. The agreement with U.S. Bank National

Association allows the Authority to borrow up to $100,000,000 and expires on December 31, 2014. The agreement

with JP Morgan Chase Bank, National Association allows the Authority to borrow up to $250,000,000 and expires

on September 15, 2014. The agreement with Wells Fargo Bank, National Association allows the Authority to

borrow up to $150,000,000 and expires on September 15, 2014. The agreement with TD Bank, N.A. allows the

Authority to borrow up to $100,000,000 and expires on November 27, 2015. The agreement with Barclays Bank

PLC allows the Authority to borrow up to $200,000,000 and expires on November 27, 2015. 

The Authority’s obligation to repay any such loans is secured by a lien upon and pledge of Revenues pari

passu with the lien upon and pledge of Revenues securing the Commercial Paper Notes. No loans are outstanding

under the Revolving Credit Agreements.

Purpose of the 2014M1 Bonds

The 2014M1 Bonds are being issued to fund a portion of the cost of the Authority’s ongoing capital

improvement program. See “CAPITAL IMPROVEMENT PROGRAM.”

DESCRIPTION OF THE CURRENT INTEREST BEARING BONDS

General

The Current Interest Bearing Bonds will be dated May 1, 2014 and will mature on January 1, 2019 at the

interest rate of 1.75%, on January 1, 2024 at the interest rate of 3.00%, on January 1, 2029 at the interest rate of

4.00%, and on January 1, 2034 at the interest rate of 4.30%. The Current Interest Bearing Bonds will be issued

as registered bonds without coupons in the denominations of five hundred ($500) dollars or any integral multiple

thereof and when issued will initially be in book-entry form. See “DESCRIPTION OF BOOK-ENTRY ONLY

SYSTEM.” Interest on the Current Interest Bearing Bonds, payable semiannually on each January 1 and July 1

commencing January 1, 2015 (at which time 240 days of interest will be due), and maturing principal of the Current

Interest Bearing Bonds will be payable by check or draft mailed by The Bank of New York Mellon Trust

Company, N.A., as Trustee, to the registered owners thereof as shown on the registration books on the fifteenth

day of the month prior to each payment date. The total combined order of the Current Interest Bearing Bonds and

Capital Appreciation Bonds, as measured by the initial purchase price thereof per series, which may be initially

purchased by any one investor shall be $50,000. The Current Interest Bearing Bonds may be transferred to another

owner but only on the registration books of the Authority held by the Trustee, as registrar. 

2
Redemption

The Current Interest Bearing Bonds shall be subject to redemption prior to maturity at the option of the

Authority on and after January 1, 2015, upon not less than 30 days written notice, as a whole at any time, or in part

from time to time on any interest payment date (and, in the event that less than all of the Current Interest Bearing

Bonds are called for redemption, the particular Current Interest Bearing Bonds or portions thereof to be redeemed

shall be selected by lot by the Trustee, but only in integral multiples of $500 denominations), at the redemption

price of 100% of the principal amount of each Current Interest Bearing Bond to be redeemed, together with the

interest accrued thereon to the date fixed for redemption.

Purchase of Current Interest Bearing Bonds by Authority

On or after January 1, 2015 any Current Interest Bearing Bond (or portion thereof in authorized

denomination) will be purchased by the Authority, on the demand of the registered owner thereof, on the first day

(or, if such day is not a business day, on the next succeeding business day) of the first or second month next

succeeding the date of delivery of the written notice to the Authority at a purchase price equal to the principal

amount thereof less a fee of $15 per $500 principal amount to be purchased, together with accrued interest to the

purchase date, upon delivery to the Authority, of not less than 30 days written notice, properly endorsed with

signature guaranteed, which states (i) the CUSIP number, face amount, maturity date and series designation of the

Current Interest Bearing Bond to be purchased, and (ii) the portion of the principal amount of such Current Interest

Bearing Bond to be purchased (provided that such portion shall be an integral multiple of $500). 

The Authority’s obligation to purchase 2014M1 Bonds tendered for purchase is limited to 5% of the

original issue amount of the 2014M1 Bonds in any calendar year. Purchases will also be limited on a monthly basis

to one-twelfth of the 5% annual maximum. Purchases will be processed in the order of receipt by the Authority

of tenders for purchase. 

DESCRIPTION OF THE CAPITAL APPRECIATION BONDS

General

The Capital Appreciation Bonds will be dated May 1, 2014 and will mature on January 1, 2023 at the

interest rate of 3.00%, on January 1, 2028 at the interest rate of 4.00% and on January 1, 2033 at the interest rate

of 4.30%. The Capital Appreciation Bonds are payable in an amount (the “Accreted Value”) equal to the principal

amount of such Capital Appreciation Bonds plus interest from the date of such Capital Appreciation Bonds,

compounded on January 1 and July 1 of each year. The Capital Appreciation Bonds will be issued as registered

bonds without coupons in the denominations of two hundred ($200) dollars or any integral multiple thereof and

when issued will initially be in book-entry form. See “DESCRIPTION OF BOOK-ENTRY ONLY SYSTEM.” 

The Capital Appreciation Bonds will bear interest on the original principal amounts thereof, compounded

semiannually on January 1 and July 1 of each year commencing January 1, 2015, and payable only upon maturity

or earlier redemption or elective purchase thereof. The maturing Accreted Value of the Capital Appreciation Bonds

and Current Interest Bearing Bonds, as measured by the initial purchase price thereof per series, which may be

initially purchased by any one investor shall be $50,000. The Capital Appreciation Bonds may be transferred to

another owner but only on the registration books of the Authority held by the Trustee, as registrar. 

Redemption

The Capital Appreciation Bonds shall be subject to redemption prior to maturity at the option of the

Authority on and after January 1, 2015, upon not less than 30 days written notice, as a whole at any time, or in part

from time to time on any January 1 or July 1 (and, in the event that less than all of the Capital Appreciation Bonds

are called for redemption, the particular Capital Appreciation Bonds or portions thereof to be redeemed shall be

selected by lot by the Trustee, but only in integral multiples of $200 denominations), at a redemption price equal

to the Accreted Value on the redemption date of any such Capital Appreciation Bond to be redeemed.

3
Purchase of Capital Appreciation Bonds by Authority

On or after January 1, 2015 any Capital Appreciation Bond (or portion thereof in authorized

denomination) will be purchased by the Authority, on the demand of the registered owner thereof, on the first day

(or, if such day is not a business day, on the next succeeding business day) of the first or second month next

succeeding the date of delivery of the written notice to the Authority at 100% of the Accreted Value thereof on the

date of purchase less a fee of $6.00 per $200 original principal amount to be purchased, upon delivery to the

Authority, of not less than 30 days written notice, properly endorsed with signature guaranteed, which states (i)

the CUSIP number, original principal amount, maturity date and series designation of the Capital Appreciation

Bond to be purchased, and (ii) the portion of the original principal amount of such Capital Appreciation Bond to

be purchased (provided that such portion shall be an integral multiple of $200).

The Authority’s obligation to purchase 2014M1 Bonds tendered for purchase is limited to 5% of the

original issue amount of the 2014M1 Bonds in any calendar year. Purchases will also be limited on a monthly basis

to one-twelfth of the 5% annual maximum. Purchases will be processed in the order of receipt by the Authority

of tenders for purchase. 

[Remainder of page intentionally left blank.]

4
Accreted Value Table for Capital Appreciation Bonds Maturity January 1, 2023

The Accreted Value amount due at optional redemption, elective purchase or maturity of each $200

original principal amount of any Capital Appreciation Bond with a maturity date of January 1, 2023, as of the first

day of each month to maturity will be set forth below. The Accreted Value of each $200 original principal amount

of any Capital Appreciation Bond on any other date will be calculated on the assumption that such Accreted Value

increases in equal daily amounts on the basis of twelve 30-day months.

 Date 

Accreted

 Value Date 

Accreted

 Value Date 

Accreted

 Value 

Jan. 1, 2015 ........ $204.02 Jul. 1, 2018 ....... $226.43 Jan. 1, 2022 ....... $251.30

Feb. 1, 2015 ........ 204.52 Aug. 1, 2018 ..... 226.99 Feb. 1, 2022 ....... 251.92

Mar. 1, 2015 ........ 205.03 Sep. 1, 2018 ...... 227.55 Mar. 1, 2022 ....... 252.55

Apr. 1, 2015 ........ 205.54 Oct. 1, 2018 ...... 228.12 Apr. 1, 2022 ....... 253.17

May 1, 2015 ........ 206.05 Nov. 1, 2018 ..... 228.68 May 1, 2022 ....... 253.80

Jun. 1, 2015 ........ 206.56 Dec. 1, 2018 ...... 229.25 Jun. 1, 2022 ....... 254.43

Jul. 1, 2015 ......... 207.08 Jan. 1, 2019 ...... 229.82 Jul. 1, 2022 ........ 255.07

Aug. 1, 2015 ....... 207.59 Feb. 1, 2019 ...... 230.39 Aug. 1, 2022 ...... 255.70

Sep. 1, 2015 ........ 208.11 Mar. 1, 2019 ...... 230.96 Sep. 1, 2022 ....... 256.34

Oct. 1, 2015 ........ 208.62 Apr. 1, 2019 ...... 231.54 Oct. 1, 2022 ....... 256.97

Nov. 1, 2015 ....... 209.14 May 1, 2019 ...... 232.11 Nov. 1, 2022 ...... 257.61

Dec. 1, 2015 ........ 209.66 Jun. 1, 2019 ...... 232.69 Dec. 1, 2022 ....... 258.25

Jan. 1, 2016 ........ 210.18 Jul. 1, 2019 ....... 233.27 Jan. 1, 2023 ....... 258.89

Feb. 1, 2016 ........ 210.70 Aug. 1, 2019 ..... 233.85

Mar. 1, 2016 ........ 211.23 Sep. 1, 2019 ...... 234.43

Apr. 1, 2016 ........ 211.75 Oct. 1, 2019 ...... 235.01

May 1, 2016 ........ 212.28 Nov. 1, 2019 ..... 235.60

Jun. 1, 2016 ........ 212.81 Dec. 1, 2019 ...... 236.18

Jul. 1, 2016 ......... 213.33 Jan. 1, 2020 ...... 236.77

Aug. 1, 2016 ....... 213.86 Feb. 1, 2020 ...... 237.36

Sep. 1, 2016 ........ 214.40 Mar. 1, 2020 ...... 237.95

Oct. 1, 2016 ........ 214.93 Apr. 1, 2020 ...... 238.54

Nov. 1, 2016 ....... 215.46 May 1, 2020 ...... 239.13

Dec. 1, 2016 ........ 216.00 Jun. 1, 2020 ...... 239.72

Jan. 1, 2017 ........ 216.53 Jul. 1, 2020 ....... 240.32

Feb. 1, 2017 ........ 217.07 Aug. 1, 2020 ..... 240.92

Mar. 1, 2017 ........ 217.61 Sep. 1, 2020 ...... 241.51

Apr. 1, 2017 ........ 218.15 Oct. 1, 2020 ...... 242.11

May 1, 2017 ........ 218.69 Nov. 1, 2020 ..... 242.72

Jun. 1, 2017 ........ 219.24 Dec. 1, 2020 ...... 243.32

Jul. 1, 2017 ......... 219.78 Jan. 1, 2021 ...... 243.92

Aug. 1, 2017 ....... 220.33 Feb. 1, 2021 ...... 244.53

Sep. 1, 2017 ........ 220.88 Mar. 1, 2021 ...... 245.14

Oct. 1, 2017 ........ 221.42 Apr. 1, 2021 ...... 245.75

Nov. 1, 2017 ....... 221.97 May 1, 2021 ...... 246.36

Dec. 1, 2017 ........ 222.53 Jun. 1, 2021 ...... 246.97

Jan. 1, 2018 ........ 223.08 Jul. 1, 2021 ....... 247.58

Feb. 1, 2018 ........ 223.63 Aug. 1, 2021 ..... 248.20

Mar. 1, 2018 ........ 224.19 Sep. 1, 2021 ...... 248.81

Apr. 1, 2018 ........ 224.75 Oct. 1, 2021 ...... 249.43

May 1, 2018 ........ 225.30 Nov. 1, 2021 ..... 250.05

Jun. 1, 2018 ........ 225.86 Dec. 1, 2021 ...... 250.67

5
Accreted Value Table for Capital Appreciation Bonds Maturity January 1, 2028

The Accreted Value amount due at optional redemption, elective purchase or maturity of each $200

original principal amount of any Capital Appreciation Bond with a maturity date of January 1, 2028, as of the first

day of each month to maturity will be set forth below. The Accreted Value of each $200 original principal amount

of any Capital Appreciation Bond on any other date will be calculated on the assumption that such Accreted Value

increases in equal daily amounts on the basis of twelve 30-day months.

 Date 

Accreted

 Value Date 

Accreted

 Value Date 

Accreted

 Value 

Jan. 1, 2015 ........ $205.36 Jul. 1, 2018 ....... $235.89 Jan. 1, 2022 ....... $270.97

Feb. 1, 2015 ........ 206.04 Aug. 1, 2018 ..... 236.67 Feb. 1, 2022 ....... 271.86

Mar. 1, 2015 ........ 206.72 Sep. 1, 2018 ...... 237.46 Mar. 1, 2022 ....... 272.76

Apr. 1, 2015 ........ 207.40 Oct. 1, 2018 ...... 238.24 Apr. 1, 2022 ....... 273.66

May 1, 2015 ........ 208.09 Nov. 1, 2018 ..... 239.03 May 1, 2022 ....... 274.57

Jun. 1, 2015 ........ 208.78 Dec. 1, 2018 ...... 239.82 Jun. 1, 2022 ....... 275.48

Jul. 1, 2015 ......... 209.47 Jan. 1, 2019 ...... 240.61 Jul. 1, 2022 ........ 276.39

Aug. 1, 2015 ....... 210.16 Feb. 1, 2019 ...... 241.41 Aug. 1, 2022 ...... 277.30

Sep. 1, 2015 ........ 210.85 Mar. 1, 2019 ...... 242.21 Sep. 1, 2022 ....... 278.22

Oct. 1, 2015 ........ 211.55 Apr. 1, 2019 ...... 243.01 Oct. 1, 2022 ....... 279.14

Nov. 1, 2015 ....... 212.25 May 1, 2019 ...... 243.81 Nov. 1, 2022 ...... 280.06

Dec. 1, 2015 ........ 212.95 Jun. 1, 2019 ...... 244.62 Dec. 1, 2022 ....... 280.99

Jan. 1, 2016 ........ 213.66 Jul. 1, 2019 ....... 245.42 Jan. 1, 2023 ....... 281.92

Feb. 1, 2016 ........ 214.36 Aug. 1, 2019 ..... 246.24 Feb. 1, 2023 ....... 282.85

Mar. 1, 2016 ........ 215.07 Sep. 1, 2019 ...... 247.05 Mar. 1, 2023 ....... 283.78

Apr. 1, 2016 ........ 215.78 Oct. 1, 2019 ...... 247.87 Apr. 1, 2023 ....... 284.72

May 1, 2016 ........ 216.50 Nov. 1, 2019 ..... 248.69 May 1, 2023 ....... 285.66

Jun. 1, 2016 ........ 217.21 Dec. 1, 2019 ...... 249.51 Jun. 1, 2023 ....... 286.61

Jul. 1, 2016 ......... 217.93 Jan. 1, 2020 ...... 250.33 Jul. 1, 2023 ........ 287.55

Aug. 1, 2016 ....... 218.65 Feb. 1, 2020 ...... 251.16 Aug. 1, 2023 ...... 288.50

Sep. 1, 2016 ........ 219.37 Mar. 1, 2020 ...... 251.99 Sep. 1, 2023 ....... 289.46

Oct. 1, 2016 ........ 220.10 Apr. 1, 2020 ...... 252.82 Oct. 1, 2023 ....... 290.41

Nov. 1, 2016 ....... 220.83 May 1, 2020 ...... 253.66 Nov. 1, 2023 ...... 291.37

Dec. 1, 2016 ........ 221.56 Jun. 1, 2020 ...... 254.50 Dec. 1, 2023 ....... 292.34

Jan. 1, 2017 ........ 222.29 Jul. 1, 2020 ....... 255.34 Jan. 1, 2024 ....... 293.30

Feb. 1, 2017 ........ 223.02 Aug. 1, 2020 ..... 256.18 Feb. 1, 2024 ....... 294.27

Mar. 1, 2017 ........ 223.76 Sep. 1, 2020 ...... 257.03 Mar. 1, 2024 ....... 295.25

Apr. 1, 2017 ........ 224.50 Oct. 1, 2020 ...... 257.88 Apr. 1, 2024 ....... 296.22

May 1, 2017 ........ 225.24 Nov. 1, 2020 ..... 258.73 May 1, 2024 ....... 297.20

Jun. 1, 2017 ........ 225.99 Dec. 1, 2020 ...... 259.59 Jun. 1, 2024 ....... 298.18

Jul. 1, 2017 ......... 226.73 Jan. 1, 2021 ...... 260.45 Jul. 1, 2024 ........ 299.17

Aug. 1, 2017 ....... 227.48 Feb. 1, 2021 ...... 261.31 Aug. 1, 2024 ...... 300.16

Sep. 1, 2017 ........ 228.24 Mar. 1, 2021 ...... 262.17 Sep. 1, 2024 ....... 301.15

Oct. 1, 2017 ........ 228.99 Apr. 1, 2021 ...... 263.04 Oct. 1, 2024 ....... 302.15

Nov. 1, 2017 ....... 229.75 May 1, 2021 ...... 263.91 Nov. 1, 2024 ...... 303.15

Dec. 1, 2017 ........ 230.51 Jun. 1, 2021 ...... 264.78 Dec. 1, 2024 ....... 304.15

Jan. 1, 2018 ........ 231.27 Jul. 1, 2021 ....... 265.66 Jan. 1, 2025 ....... 305.15

Feb. 1, 2018 ........ 232.03 Aug. 1, 2021 ..... 266.53 Feb. 1, 2025 ....... 306.16

Mar. 1, 2018 ........ 232.80 Sep. 1, 2021 ...... 267.41 Mar. 1, 2025 ...... 307.18

Apr. 1, 2018 ........ 233.57 Oct. 1, 2021 ...... 268.30 Apr. 1, 2025 ....... 308.19

May 1, 2018 ........ 234.34 Nov. 1, 2021 ..... 269.19 May 1, 2025 ....... 309.21

Jun. 1, 2018 ........ 235.12 Dec. 1, 2021 ...... 270.08 Jun. 1, 2025 ....... 310.23

6
 Date 

 Accreted

 Value Date 

Accreted

 Value Date 

Accreted

 Value 

Jul. 1, 2025 ........ $311.26 Oct. 1, 2026 ....... $327.05 Jan. 1, 2028 ....... $343.65

Aug. 1, 2025 ...... 312.29 Nov. 1, 2026 ...... 328.14

Sep. 1, 2025 ....... 313.32 Dec. 1, 2026 ....... 329.22

Oct. 1, 2025 ....... 314.35 Jan. 1, 2027 ....... 330.31

Nov. 1, 2025 ...... 315.39 Feb. 1, 2027 ....... 331.40

Dec. 1, 2025 ....... 316.44 Mar. 1, 2027 ....... 332.50

Jan. 1, 2026 ....... 317.48 Apr. 1, 2027 ....... 333.60

Feb. 1, 2026 ....... 318.53 May 1, 2027 ....... 334.70

Mar. 1, 2026 ...... 319.58 Jun. 1, 2027 ....... 335.80

Apr. 1, 2026 ....... 320.64 Jul. 1, 2027 ........ 336.91

May 1, 2026 ....... 321.70 Aug. 1, 2027 ...... 338.03

Jun. 1, 2026 ....... 322.77 Sep. 1, 2027 ....... 339.15

Jul. 1, 2026 ........ 323.83 Oct. 1, 2027 ....... 340.27

Aug. 1, 2026 ...... 324.90 Nov. 1, 2027 ...... 341.39

Sep. 1, 2026 ....... 325.98 Dec. 1, 2027 ....... 342.52

[Remainder of page intentionally left blank.]

7
Accreted Value Table for Capital Appreciation Bonds Maturity January 1, 2033

The Accreted Value amount due at optional redemption, elective purchase or maturity of each $200

original principal amount of any Capital Appreciation Bond with a maturity date of January 1, 2033, as of the first

day of each month to maturity will be set forth below. The Accreted Value of each $200 original principal amount

of any Capital Appreciation Bond on any other date will be calculated on the assumption that such Accreted Value

increases in equal daily amounts on the basis of twelve 30-day months.

 Date 

Accreted

 Value Date 

Accreted

 Value Date 

Accreted

 Value 

Jan. 1, 2015 ....... $205.76 Jul. 1, 2018 ........ $238.80 Jan. 1, 2022 ....... $277.14

Feb. 1, 2015 ....... 206.49 Aug. 1, 2018 ...... 239.65 Feb. 1, 2022 ....... 278.13

Mar. 1, 2015 ....... 207.23 Sep. 1, 2018 ....... 240.50 Mar. 1, 2022 ...... 279.12

Apr. 1, 2015 ....... 207.96 Oct. 1, 2018 ....... 241.36 Apr. 1, 2022 ....... 280.11

May 1, 2015 ....... 208.70 Nov. 1, 2018 ...... 242.21 May 1, 2022 ...... 281.10

Jun. 1, 2015 ....... 209.44 Dec. 1, 2018 ....... 243.07 Jun. 1, 2022 ....... 282.10

Jul. 1, 2015 ........ 210.19 Jan. 1, 2019 ....... 243.94 Jul. 1, 2022 ....... 283.10

Aug. 1, 2015 ...... 210.93 Feb. 1, 2019 ....... 244.80 Aug. 1, 2022 ...... 284.11

Sep. 1, 2015 ....... 211.68 Mar. 1, 2019 ....... 245.67 Sep. 1, 2022 ....... 285.12

Oct. 1, 2015 ....... 212.44 Apr. 1, 2019 ....... 246.54 Oct. 1, 2022 ....... 286.13

Nov. 1, 2015 ...... 213.19 May 1, 2019 ....... 247.42 Nov. 1, 2022 ...... 287.15

Dec. 1, 2015 ....... 213.95 Jun. 1, 2019 ....... 248.30 Dec. 1, 2022 ....... 288.17

Jan. 1, 2016 ....... 214.71 Jul. 1, 2019 ........ 249.18 Jan. 1, 2023 ....... 289.19

Feb. 1, 2016 ....... 215.47 Aug. 1, 2019 ...... 250.07 Feb. 1, 2023 ....... 290.22

Mar. 1, 2016 ....... 216.23 Sep. 1, 2019 ....... 250.95 Mar. 1, 2023 ....... 291.25

Apr. 1, 2016 ....... 217.00 Oct. 1, 2019 ....... 251.85 Apr. 1, 2023 ....... 292.28

May 1, 2016 ....... 217.77 Nov. 1, 2019 ...... 252.74 May 1, 2023 ....... 293.32

Jun. 1, 2016 ....... 218.55 Dec. 1, 2019 ....... 253.64 Jun. 1, 2023 ....... 294.36

Jul. 1, 2016 ........ 219.32 Jan. 1, 2020 ....... 254.54 Jul. 1, 2023 ........ 295.41

Aug. 1, 2016 ...... 220.10 Feb. 1, 2020 ....... 255.44 Aug. 1, 2023 ...... 296.46

Sep. 1, 2016 ....... 220.88 Mar. 1, 2020 ....... 256.35 Sep. 1, 2023 ....... 297.51

Oct. 1, 2016 ....... 221.67 Apr. 1, 2020 ....... 257.26 Oct. 1, 2023 ....... 298.57

Nov. 1, 2016 ...... 222.46 May 1, 2020 ....... 258.17 Nov. 1, 2023 ...... 299.63

Dec. 1, 2016 ....... 223.25 Jun. 1, 2020 ....... 259.09 Dec. 1, 2023 ....... 300.69

Jan. 1, 2017 ....... 224.04 Jul. 1, 2020 ........ 260.01 Jan. 1, 2024 ....... 301.76

Feb. 1, 2017 ....... 224.83 Aug. 1, 2020 ...... 260.93 Feb. 1, 2024 ....... 302.83

Mar. 1, 2017 ....... 225.63 Sep. 1, 2020 ....... 261.86 Mar. 1, 2024 ...... 303.91

Apr. 1, 2017 ....... 226.43 Oct. 1, 2020 ....... 262.79 Apr. 1, 2024 ....... 304.99

May 1, 2017 227.24 Nov. 1, 2020 ...... 263.72 May 1, 2024 ....... 306.07

Jun. 1, 2017 ....... 228.05 Dec. 1, 2020 ....... 264.66 Jun. 1, 2024 ....... 307.16

Jul. 1, 2017 ........ 228.86 Jan. 1, 2021 ....... 265.60 Jul. 1, 2024 ........ 308.25

Aug. 1, 2017 ...... 229.67 Feb. 1, 2021 ....... 266.54 Aug. 1, 2024 ...... 309.34

Sep. 1, 2017 ....... 230.48 Mar. 1, 2021 ....... 267.49 Sep. 1, 2024 ....... 310.44

Oct. 1, 2017 ....... 231.30 Apr. 1, 2021 ....... 268.44 Oct. 1, 2024 ....... 311.54

Nov. 1, 2017 ...... 232.12 May 1, 2021 ....... 269.39 Nov. 1, 2024 ...... 312.65

Dec. 1, 2017 ....... 232.95 Jun. 1, 2021 ....... 270.35 Dec. 1, 2024 ....... 313.76

Jan. 1, 2018 ....... 233.78 Jul. 1, 2021 ........ 271.31 Jan. 1, 2025 ....... 314.87

Feb. 1, 2018 ....... 234.61 Aug. 1, 2021 ...... 272.28 Feb. 1, 2025 ....... 315.99

Mar. 1, 2018 ....... 235.44 Sep. 1, 2021 ....... 273.24 Mar. 1, 2025 ....... 317.11

Apr. 1, 2018 ....... 236.28 Oct. 1, 2021 ....... 274.21 Apr. 1, 2025 ....... 318.24

May 1, 2018 ....... 237.11 Nov. 1, 2021 ...... 275.19 May 1, 2025 ....... 319.37

Jun. 1, 2018 ....... 237.96 Dec. 1, 2021 ....... 276.16 Jun. 1, 2025 ....... 320.51

8
 Date 

Accreted

 Value Date 

Accreted

 Value Date 

Accreted

 Value 

Jul. 1, 2025 ........ $321.64 Jun. 1, 2028 ........ $364.14 May 1, 2031 ....... $412.25

Aug. 1, 2025 ...... 322.79 Jul. 1, 2028 ......... 365.43 Jun. 1, 2031 ....... 413.71

Sep. 1, 2025 ....... 323.93 Aug. 1, 2028 ....... 366.73 Jul. 1, 2031 ........ 415.18

Oct. 1, 2025 ....... 325.08 Sep. 1, 2028 ........ 368.03 Aug. 1, 2031 ...... 416.65

Nov. 1, 2025 ...... 326.24 Oct. 1, 2028 ........ 369.34 Sep. 1, 2031 ....... 418.13

Dec. 1, 2025 ....... 327.40 Nov. 1, 2028 ....... 370.65 Oct. 1, 2031 ....... 419.62

Jan. 1, 2026 ....... 328.56 Dec. 1, 2028 ........ 371.97 Nov. 1, 2031 ...... 421.11

Feb. 1, 2026 ....... 329.73 Jan. 1, 2029 ........ 373.29 Dec. 1, 2031 ....... 422.60

Mar. 1, 2026 ....... 330.90 Feb. 1, 2029 ........ 374.61 Jan. 1, 2032 ....... 424.11

Apr. 1, 2026 ....... 332.07 Mar. 1, 2029 ........ 375.94 Feb. 1, 2032 ....... 425.61

May 1, 2026 ....... 333.25 Apr. 1, 2029 ........ 377.28 Mar. 1, 2032 ....... 427.12

Jun. 1, 2026 ....... 334.44 May 1, 2029 ........ 378.62 Apr. 1, 2032 ....... 428.64

Jul. 1, 2026 ........ 335.62 Jun. 1, 2029 ........ 379.96 May 1, 2032 ....... 430.16

Aug. 1, 2026 ...... 336.82 Jul. 1, 2029 ......... 381.31 Jun. 1, 2032 ....... 431.69

Sep. 1, 2026 ....... 338.01 Aug. 1, 2029 ....... 382.67 Jul. 1, 2032 ........ 433.22

Oct. 1, 2026 ....... 339.21 Sep. 1, 2029 ........ 384.03 Aug. 1, 2032 ...... 434.76

Nov. 1, 2026 ...... 340.42 Oct. 1, 2029 ........ 385.39 Sep. 1, 2032 ....... 436.31

Dec. 1, 2026 ....... 341.63 Nov. 1, 2029 ....... 386.76 Oct. 1, 2032 ....... 437.86

Jan. 1, 2027 ....... 342.84 Dec. 1, 2029 ........ 388.13 Nov. 1, 2032 ...... 439.41

Feb. 1, 2027 ....... 344.06 Jan. 1, 2030 ........ 389.51 Dec. 1, 2032 ....... 440.97

Mar. 1, 2027 ....... 345.28 Feb. 1, 2030 ........ 390.90 Jan. 1, 2033 ....... 442.54

Apr. 1, 2027 ....... 346.51 Mar. 1, 2030 ........ 392.28

May 1, 2027 ....... 347.74 Apr. 1, 2030 ........ 393.68

Jun. 1, 2027 ....... 348.97 May 1, 2030 ........ 395.08

Jul. 1, 2027 ........ 350.21 Jun. 1, 2030 ........ 396.48

Aug. 1, 2027 ...... 351.45 Jul. 1, 2030 ......... 397.89

Sep. 1, 2027 ....... 352.70 Aug. 1, 2030 ....... 399.30

Oct. 1, 2027 ....... 353.96 Sep. 1, 2030 ........ 400.72

Nov. 1, 2027 ...... 355.21 Oct. 1, 2030 ........ 402.14

Dec. 1, 2027 ....... 356.47 Nov. 1, 2030 ....... 403.57

Jan. 1, 2028 ....... 357.74 Dec. 1, 2030 ........ 405.00

Feb. 1, 2028 ....... 359.01 Jan. 1, 2031 ........ 406.44

Mar. 1, 2028 ....... 360.29 Feb. 1, 2031 ........ 407.88

Apr. 1, 2028 ....... 361.57 Mar. 1, 2031 ........ 409.33

May 1, 2028 ....... 362.85 Apr. 1, 2031 ........ 410.79

DESCRIPTION OF BOOK-ENTRY ONLY SYSTEM

Unless and until the book-entry only system is discontinued, the 2014M1 Bonds will be available only

in book-entry form in authorized denominations. Owners of the 2014M1 Bonds will be listed in the books of

record of the Registrar. Owners of the 2014M1 Bonds will not receive physical bond certificates representing their

interests in the 2014M1 Bonds purchased.

Transfers of ownership interests in the 2014M1 Bonds are to be accomplished by entries made on the

books of the Trustee acting on behalf of Owners. Owners will not receive certificates representing their ownership

interests in the 2014M1 Bonds, unless the use of the book-entry system for the 2014M1 Bonds is discontinued.

9
LONG-TERM CAPITAL STRUCTURE PLAN

Traditionally, the Authority has amortized its debt taking into consideration the potential termination of

the Central Agreement hereafter defined, and the expected lives of its capital assets. See “CUSTOMER BASE --

Wholesale - Central.” In light of the recent extension of the earliest possible termination date of the Central

Agreement from 2030 to 2058, the Authority intends to extend the average life of its debt in order to better align

its debt amortization to the expected lives of its capital assets. The Authority will achieve this alignment by a

combination of selling longer dated debt for the Authority’s current and future capital projects, combined with a

multi-year refinancing program that will extend the maturity of a portion of the Authority’s debt. The ultimate

amount of debt extension will be impacted by a number of factors, including the Authority’s ownership percentage

of the new nuclear units described below. While the size and scope of this restructuring program will evolve over

time, the Authority currently projects that up to $900 million of bonds maturing through 2031 could be refunded

and extended over the term of this program. As an alternative to a portion of these potential refundings, the

Authoritymay obtain a portion ofits desired debt alignment by deferring the principal amortization offuture capital

project issues. 

FINANCING PLAN FOR SUMMER NUCLEAR UNITS 2 AND 3

The Authority currently estimates the total construction cost associated with a 45% ownership interest

in the Virgil C. Summer Nuclear Generating Station Units 2 and 3 (“Summer Nuclear Unit 2" and “Summer

Nuclear Unit 3” and together “Summer Nuclear Units 2 and 3") to be approximately $5.1 billion including

approximately $159 million for transmission and approximately $138 million for the initial fuel core. Except for

a small portion of the transmission cost associated with Summer Nuclear Units 2 and 3, the Authority expects to

fund the construction with debt and with the proceeds of a sale of a portion of its ownership interest in Summer

Nuclear Units 2 and 3 to South Carolina Electric & Gas (“SCE&G”). To date, the Authority has financed

approximately $2.5 billion for construction from proceeds of issues sold beginning in 2008. The remaining

requirements for construction are approximately $2.6 billion. The Authority intends to fund the remaining

construction with the proceeds of additional bond sales projected in calendar years 2014 through 2018 and proceeds

from the sale of a 5% ownership interest to SCE&G. While the Authority expects to fund the remaining

construction of Summer Nuclear Units 2 and 3 with parity indebtedness, it also has a pending application with the

Department of Energy (“DOE”) for a loan guarantee to fund construction should it be beneficial to do so. See

“CAPITAL IMPROVEMENT PROGRAM -- Summer Nuclear Units 2 and 3.”

[Remainder of page intentionally left blank.]

10
DEBT SERVICE SCHEDULE(1)

(Thousands of Dollars)

The following table sets forth on an accrual basis the debt service due on outstanding Revenue

Obligations, the 2014M1 Bonds, and the total debt service in each calendar year indicated. 

Outstanding 

Revenue 

Obligations(2)

2014M1

 Bonds 

Total

Debt

 Service

2014 $ 498,023 $ $

2015 842,758(3)

2016 609,597(3)

2017 452,391

2018 468,813

2019 435,682

2020 426,936

2021 441,141

2022 368,615

2023 334,020

2024 336,882

2025 314,380

2026 314,860

2027 316,571

2028 326,138

2029 331,640

2030 304,945

2031 283,205

2032 256,843

2033 284,973

2034 286,911

2035 304,831

2036 305,682

2037 264,646

2038 222,839

2039 203,921

2040 225,606

2041 225,615

2042 222,359

2043 226,166

2044 147,426

2045 144,231

2046 141,714

2047 139,201

2048 135,607

2049 121,363

2050 59,519

2051 59,516

2052 59,515

2053 54,563

 _________ 

11
(1) Does not include payments into the Lease Fund or debt service on Commercial Paper Notes, both of which are junior to debt service on

Revenue Obligations. Does not reflect puts subsequent to December 15, 2013 of Revenue Obligations subject to tender for elective

purchase. 

(2) Net of Subsidy Payment (hereinafter defined). Subject to the Authority’s compliance with certain requirements under the American

Recovery and Reinvestment Act of 2009 and the Internal Revenue Code of 1986, as amended (the “Code”), the Authority expects to

receive cash subsidy payments from the United States Treasury equal to 35% of the interest payable on the Revenue Obligations, 2010

Series C Bonds (the “2010C Bonds”) (any such payment, a “Subsidy Payment”). Pursuant to the requirements of the Balanced Budget

and Emergency Deficit Control Act of 1985, as amended, certain automatic reductions took place March 1, 2013. These required

reductions includes a reduction to refundable credits under section 6431 of the Internal Revenue Code applicable to certain qualified

bonds. The sequestration reduction rate of 7.2% has been applied to the July 1, 2014 and January 1, 2015 Subsidy Payments respectively,

and the debt service on Revenue Obligations in calendar years 2014 and 2015 has been adjusted accordingly.

(3) Principal on the $450,000,000 2013 Taxable Series D (LIBOR Index Bonds) is shown in the year due rather than on an accrual basis and

the interest is based on a projected 1 Month LIBOR rate of 1.00%.

SECURITY FOR THE 2014M1 BONDS

General

The 2014M1 Bonds are payable solely from, and secured by a lien upon and pledge of, the Revenues on

a parity with the lien and pledge securing Revenue Obligations heretofore and hereafter issued pursuant to the

Revenue Obligation Resolution, senior to (i) payments required to be made from or retained in the Revenue Fund

to pay expenses of operating and maintaining the System, and (ii) the payments into the Lease Fund and the Capital

Improvement Fund heretofore established and continued under the Revenue Obligation Resolution. See

“FINANCIAL INFORMATION.” In the Revenue Obligation Resolution the Authority has covenanted not to incur

any indebtedness senior to the lien of the Revenue Obligations. 

The Revenue Obligations, including the 2014M1 Bonds, are not obligations of the State, nor of any

political subdivision thereof, and neither the State nor any of its political subdivisions shall be liable thereon, nor

shall they be payable from any funds other than the Revenues of the Authority pledged to the payment thereof.

Additional series of Revenue Obligations may be issued without limitation and without compliance with

any additional bonds test, provided there is no default under the Revenue Obligation Resolution. In addition, no

debt service reserve fund is established under the Revenue Obligation Resolution. See Appendix II --

“SUMMARY OF CERTAIN PROVISIONS OF THE REVENUE OBLIGATION RESOLUTION.”

Rate Covenant

The Revenue Obligation Resolution provides that the Authority shall establish, maintain and collect rents,

tolls, rates and other charges for power and energy and all other services, facilities and commodities sold, furnished

or supplied through the facilities of the System which shall be adequate to provide the Authority with Revenues

sufficient: (a) to pay the principal of, premium, if any, and interest on the Revenue Obligations as and when the

same shall become due and payable; (b) to make when due all payments which the Authority is obligated to make

(i) into the Revenue Obligation Fund created under the Revenue Obligation Resolution, (ii) into the Lease Fund,

and (iii) into the Capital Improvement Fund pursuant to the Revenue Obligation Resolution; (c) to make all other

payments which the Authority is obligated to make pursuant to the Revenue Obligation Resolution; (d) to pay all

proper operation and maintenance expenses and all necessary repairs, replacements and renewals thereof; (e) to

pay all taxes, assessments or other governmental charges lawfully imposed on the Authority or the Revenues

thereof or payments in lieu thereof; and (f) to pay any and all amounts which the Authority may become obligated

to pay from the Revenues of the System by law or by contract.

As required by the Act, the Authority makes distributions to the State and payments in lieu of taxes to

local governments. Nothing in the Act prohibits the Authority from paying to the State each year up to 1% of its

projected operating revenues, as such revenues would be determined on an accrual basis, from the combined

electric and water systems. In 2013, distributions to the State and payments to local governments amounted to

approximately $30,525,000.

There is no governmental or regulatory entity, other than the Authority’s Board of Directors, having

jurisdiction over the rates of the Authority. 

12
Additional Indebtedness

The Revenue Obligation Resolution does not prohibit the issuance of obligations secured by a pledge of

the Revenues junior and subordinate to the pledge securing the Revenue Obligations. In addition, the Authority

may issue obligations secured by a pledge of revenues derived from separate utility systems not included in the

System. See Appendix II -- “SUMMARY OF CERTAIN PROVISIONS OF THE REVENUE OBLIGATION

RESOLUTION -- Separate Systems.”

Capital Improvement Fund Requirement

The Revenue Obligation Resolution requires, so long as any Revenue Obligations are outstanding, that

the Authority deposit annually into the Capital Improvement Fund an amount which, together with the amounts

deposited therein in the two immediately preceding Fiscal Years, will be at least equal to 8% of the Revenues

required by the Revenue Obligation Resolution to be paid into the Revenue Fund in the three immediately

preceding Fiscal Years. Permitted use of moneys in the Capital Improvement Fund includes but is not limited to

payment of Capital Costs, as defined in the Revenue Obligation Resolution. See Appendix II --“SUMMARY OF

CERTAIN PROVISIONS OF THE REVENUE OBLIGATION RESOLUTION.”

ORGANIZATION AND MANAGEMENT OF THE AUTHORITY

The Act contains provisions governing the composition, qualifications, appointment and duties of the

Authority’s Board of Directors. The Governor appoints members, and the State Regulation of Public Utilities

Review Committee (“PURC”) screens appointees to determine whether they have the qualifications required by

the Act. After successful screening, appointees must be confirmed by the State Senate. The Act describes the

duties of directors and sets forth conditions by which a director may be held accountable for his actions or inactions

as a director. 

The Board consists of twelve members who reside in South Carolina as follows: one from each

congressional district of the State; one from each of the counties of Berkeley, Horry and Georgetown who reside

in the territory of the Authority and are customers of the Authority, and two from the State at large, one of whom

shall be chairman. Two of the directors must have substantial work experience within the operations of electric

cooperatives or substantial experience on an electric cooperative board, but must not serve as an employee or board

member of an electric cooperative during their term as director of the Authority. One of the two must have

substantial experience within the operations or board of a transmission or generation cooperative.

Directors serve for a term of seven years and until a successor has been appointed and found qualified. 

Directors appointed to fill a vacancy on the Board serve for the unexpired portion of the term and until a successor

is appointed and found qualified. An individual appointed and found qualified by the PURC while the State Senate

is not in session may serve as director in an interim capacity. Directors may be removed from office only for cause.

[Remainder of page intentionally left blank.]

13
Present directors are listed below. W. Leighton Lord, III became Chairman on June 6, 2013, creating

a vacancy for the Second Congressional District. Director David A Springs died on October 31, 2013, creating

a vacancy for Georgetown County. Director James R. Sanders, Jr. resigned effective December 31, 2013, creating

a vacancy for the Fifth Congressional District. The recently created Seventh Congressional District is vacant. The

board terms for Directors Kristofer Clark, Cecil Viverette and J. Calhoun Land, IV have expired, but Board

Members may continue to serve until successors have been appointed and qualified. 

On February 20, 2014, the Governor re-appointed Director Kristofer Clark as Director for the Third

Congressional District, re-appointed Director J. Calhoun Land, IV as Director for the Sixth Congressional District,

appointed Jack Wolfe as Director for the Second Congressional District, appointed Merrill Floyd as Director for

the Seventh Congressional District, appointed Dan Ray as Director for Georgetown County and appointed

Catherine Heigel to the at-large position currently held by Director Viverette. The newly appointed persons will

not take office as a Director until such time as the screening process and confirmation by the Senate occurs. It is

expected that the confirmation process will conclude by mid-June 2014.

Term

Expires

 Name Business Residence May 

W. Leighton Lord, III,

 Chairman Attorney Columbia 2018

William A. Finn,

 First Vice Chairman Business Executive Charleston 2020

Barry D. Wynn,

 Second Vice Chairman Business Executive Spartanburg 2014

Kristofer Clark Business Executive Easley 2012(1)

Cecil E. Viverette Retired Business Executive Hilton Head 2012(1)

J. Calhoun Land, IV Attorney Manning 2013(1)

Peggy H. Pinnell Business Executive Moncks Corner 2014

David F. Singleton Business Executive Myrtle Beach 2016

______________

(1) Although their terms expired as indicated, they may continue to serve until successors have been appointed

and qualified.

The President and Chief Executive Officer of the Authority is appointed by the Authority’s Board of

Directors. The Authority's executive management is appointed by the President and Chief Executive Officer with

the approval of the Authority’s Board of Directors.

Authority executive management is:

Utility

 Name Position Experience

Lonnie N. Carter President and Chief Executive Officer 31 years

James E. Brogdon, Jr. Executive Vice President and General Counsel 9 years

Rennie M. Singletary, III Executive Vice President, Corporate Services 36 years

Jeffrey D. Armfield Senior Vice President and Chief Financial Officer 30 years

Robert B. Fleming, Jr. Senior Vice President, Power Delivery 21 years

L. Phil Pierce Senior Vice President, Generation 35 years

Marc R. Tye Senior Vice President, Customer Service 31 years

Lonnie N. Carter joined the Authority in 1982 as an employee in the Controller’s Office. Since that time

he has held various positions, including Manager of Corporate Forecasting, Vice President of Corporate

Forecasting, Senior Vice President of Customer Service and Senior Vice President of Corporate Planning & Bulk

Power. In 1997, he served as the first President and Chief Executive Officer of The Energy Authority, Inc.

(“TEA”), a joint power marketing alliance through a non-profit corporation, whereby the Authority can purchase

or sell energy and/or capacity when available. In 2004, he became President and Chief Executive Officer. He

received a Bachelor of Science degree in Business Administration and a Masters in Business Administration from

The Citadel. 

14
James E. Brogdon, Jr. joined the Authority in 2005 as Senior Vice President and General Counsel and a

member of the executive management team. He practiced law in private practice and served as a judge of the South

Carolina Circuit Court from 1996 to February 2005. He received a Bachelor of Arts degree in Economics from

Wofford College and a Juris Doctor degree from the University of South Carolina School of Law. James E.

Brogdon, Jr. will retire on June 30, 2014. Effective July 1, 2014, J. Michael Baxley will become Senior Vice

President and General Counsel. 

Rennie M. Singletary joined the Authority in 1977 as an engineer. Since that time he has held various

positions, including Jefferies Generating Station Manager and Vice President of Fossil and Hydro Generation.

He received a Bachelor of Science degree and a Master of Science degree in Mechanical Engineering from

Clemson University and a Masters in Business Administration from The Citadel. Rennie M. Singletary will retire

on April 30, 2014. Effective May 1, 2014, Pamela J. Williams will become Senior Vice President, Corporate

Services.

Jeffrey D. Armfield became Senior Vice President and Chief Financial Officer on July 1, 2013. He joined

the Authority in 1983 as a Senior Auditor. Since that time he has held various positions, including Vice President,

Fuels Strategy and Supply, Treasurer and Director of Financial Planning. He received a Bachelor of Science

degree in Business and a Masters in Business Administration from The Citadel and is a Certified Public

Accountant.

Robert B. Fleming, Jr. became Senior Vice President, Power Delivery on July 1, 2013. He joined the

Authority in 1992 as an engineer. Since that time he has held various positions including Manager of Transmission

Operations, Superintendent of System Substation Maintenance and Supervisor of Mechanical Maintenance at Cross

Generating Station. He received a Bachelor of Science degree in Electrical Engineering from the University of

South Carolina and a Masters in Business Administration from The Citadel. 

L. Phil Pierce joined the Authority in 1979 as an engineer. Since that time he has held various positions,

including Manager of Performance & Environmental Services and Manager of Cross Station Construction. He

received a Bachelor of Science degree in Mechanical Engineering from Clemson University.

Marc R. Tye joined the Authority in 1984 as an engineer. Since that time he has held various positions,

including Manager of Corporate Analysis & Pricing and Manager of Wholesale Markets. He received a Bachelor

of Science degree in Electrical Engineering and a Masters in Business Administration from The Citadel. 

Effective May 1, 2014, Michael R. Crosby will become Senior Vice President of Nuclear Energy and serve

as a member of Executive Management. 

The Authority had 1,726 employees as of February 28, 2014. Authority employees are members of a

contributory state pension plan administered by the South Carolina State Retirement System.

The Act establishes an Advisory Board composed of the following officials of the State: the Governor, the

Attorney General, the State Treasurer, the Comptroller General and the Secretary of State. The Advisory Board

approves the hiring of the external auditors and sets the salary of the Authority’s Board of Directors.

CUSTOMER BASE

Service Area

The Authority’s primary business operation is the production, transmission and distribution of electrical

energy, both at wholesale and retail, to citizens of South Carolina. In 2013, the Authority’s kilowatt-hour (“kWh”)

energy sales were comprised of 57.8% to wholesale customers, 28.1% to large industrial customers and 14.1% to

residential, commercial and other customers. The Authority is one of the nation’s largest municipal wholesale

utilities, whose System serves directly or indirectly approximately 2 million South Carolinians in all 46 counties

of South Carolina. The Authority serves directly and indirectly suburban areas outside Charleston, Columbia,

Greenville and Spartanburg as well as the coastal areas of Myrtle Beach and the Grand Strand, Hilton Head Island,

Kiawah Island and Seabrook Island. See “HISTORICAL SALES – Historical Demand, Sales and Revenues.”

15
The Authority's direct customers currently include 28 large industrial customers, Central Electric Power

Cooperative Inc. (“Central”), and two municipal electric systems, the City of Georgetown and the City of Bamberg. 

Central is an association of 20 electric distribution cooperatives, including the five electric distribution cooperatives

that were formerly members of Saluda River Electric Cooperative, Inc. (“Saluda”). Central serves primarily

residential, commercial and small industrial customers in all 46 counties of the State. Through Central and the two

municipal electric systems, the Authority indirectly serves approximately 747,000 customers. See “CUSTOMER

BASE - Wholesale - Central” and “CUSTOMER BASE - Wholesale - Other.”

The Authority also serves directly approximately 169,000 residential, commercial and small industrial retail

customers in its assigned retail service territory, which includes parts of Berkeley, Georgetown and Horry counties. 

See “CUSTOMER BASE - Direct Retail Service Area.”

Under State law, the Authority has an exclusive right to serve within its assigned retail service territory, and

it has the exclusive right to continue to serve the large industrial premises outside its assigned service territory that

it is currently serving.

Wholesale - Central

Central is a generation and transmission cooperative that provides wholesale electric service to each of the

20 distribution cooperatives (the “Central Cooperatives”) which are members of Central pursuant to long-term all

requirements power supply agreements. The Central Cooperatives serve areas ranging from sparsely populated

rural areas to heavily populated suburban areas. The table below lists each of the Central Cooperatives, the

location of their headquarters, and the number of customers of each as of December 31, 2012, which is the latest

information provided to the Authority.

 Central Cooperatives Headquarters Customers

Aiken Electric Cooperative, Inc. Aiken 45,712

Berkeley Electric Cooperative, Inc. Moncks Corner 85,645

Black River Electric Cooperative, Inc. Sumter 31,481

Blue Ridge Electric Cooperative, Inc.(1) Pickens 63,582

Broad River Electric Cooperative, Inc.(1) Gaffney 20,450

Coastal Electric Cooperative, Inc. Walterboro 11,502

Edisto Electric Cooperative, Inc. Bamberg 19,907

Fairfield Electric Cooperative, Inc. Winnsboro 26,151

Horry Electric Cooperative, Inc. Conway 67,993

Laurens Electric Cooperative, Inc.(1) Laurens 53,164

Little River Electric Cooperative, Inc.(1) Abbeville 14,056

Lynches River Electric Cooperative, Inc. Pageland 20,450

Marlboro Electric Cooperative, Inc. Bennettsville 6,535

Mid-Carolina Electric Cooperative, Inc. Lexington 52,193

Newberry Electric Cooperative, Inc. Newberry 12,681

Palmetto Electric Cooperative, Inc. Ridgeland 68,305

Pee Dee Electric Cooperative, Inc. Darlington 30,209

Santee Electric Cooperative, Inc. Kingstree 44,033

Tri-County Electric Cooperative, Inc. St. Matthews 17,890

York Electric Cooperative, Inc.(1) York 44,997

(1) Former members of Saluda (“Former Saluda Members”).

The Authority serves Central under the terms of an agreement between the Authority and Central which

became effective in January 1981 (as subsequently amended or revised, the “Central Agreement”). In 2013,

revenues pursuant to the Central Agreement amounted to approximately 57.8% of revenues from sales. The

Authority and Central adopted an amendment to the Central Agreement in January 1988 which included a number

of revisions to the cost of service methodology, established that the Authority would supply the total power and

energy requirements of the Central Cooperatives (with some limited exceptions) and provided that the Central

Agreement would have a perpetual duration with a 35 year initial term ending March 31, 2023 and an automatic

renewal for successive 35 year periods, subject to the right of either party to terminate the Central Agreement on

any date on or after the end of such initial 35 year term, upon giving at least 10 years’ notice.

16
September 2009 Agreement. In September 2009 Central and the Authority entered into an agreement (the

“September 2009 Agreement”) that, among other things, provided that neither party would exercise its right to

terminate the Central Agreement effective on or before December 31, 2030. The Authority agreed in the

September 2009 Agreement to allow Central to transition the purchase of the portion of the power and energy

requirements of the five Former Saluda Members directly connected to the transmission system of Duke Energy

Carolinas, LLC (“Duke Energy Carolinas”) (the “Upstate Load”) to another supplier and in January 2013, Central

began transitioning the Upstate Load to Duke Energy Carolinas, a subsidiary of Duke Energy Corporation

(“Duke”). The Upstate Load, which is approximately 22% of Central’s current energy requirements, will transition

to Duke Energy Carolinas over a six-year period beginning in 2013, and by the end of the transition in 2019, will

amount to approximately 1,000 Megawatts (“MW”).

May 2013 Revision to the Central Agreement. The Authority and Central adopted an amendment to the

Central Agreement on May 20, 2013 (the “May 2013 Revision”) that better aligns their future interests, formalizes

how they will jointly plan for new resources, and defers their rights to terminate the agreement until December 31,

2058. Under the Central Agreement’s 10 year rolling notice provisions, for a termination date of December 31,

2058, a party must give notice of termination no later than December 31, 2048. Central has entered into

requirements agreements with all 20 of its member cooperatives that extend through December 31, 2058 and

obligate those members to pay their share of Central’s costs, including costs paid under the Central Agreement.

Rates under the Central Agreement continue to be developed under a cost of service methodology and

to be adjusted automatically on a monthly basis to reflect actual fuel cost and to be adjusted on an annual basis to

reflect actual non-fuel cost, including O&M, debt service and a Capital Improvement Fund charge. Modifications

to the cost of service methodology include allocating debt service and Capital Improvement Fund charges to the

cost categories based on plant balances and allocating production related cost in a manner that reflects the nature

of the generating resources. 

Under the May 2013 Revision the requirements provisions of the Central Agreement are retained. Central

will continue to pay for its pro-rata share of the existing system resources, including Summer Nuclear Units 2 and

3. The May 2013 Revision formalizes the resource planning process and outlines how the parties will jointly plan

and determine the need for new resources. The May 2013 Revision also contains provisions that allow Central

to decide to participate or not participate in major new resources which were not completed or under construction

as of January 1, 2013. If Central decides to participate in a resource, the costs for the new resource are included

and shared under the Central Agreement. If Central decides not to participate in a proposed resource, the parties

will obtain their own resources based on their pro-rata share of the proposed resource and each party will be

responsible for the cost of its own non-shared resources.

The May 2013 Revision provides certainty to the planning process and, with the earliest termination date

deferred to December 2058, will allow the Authority to align its existing and future debt service with the useful

lives of its assets and its future revenue stream. 

The Authority supplies the total power and energy requirements of the Central Cooperatives less amounts

which Central purchases directly from Southeastern Power Administration (the “SEPA”), amounts provided by

Broad River Electric Cooperative’s ownership interest in a small run of the river hydroelectric plant, amounts

provided by Duke Energy Carolinas under the September 2009 Agreement referenced above, and small amounts

purchased from others.

 Under State law, the Authority may only serve directly new industrial customers located in its direct

service area. However, if any industrial customers located outside the Authority's service area discontinue

accepting electrical service from the Authority, the Authority may sell electrical service to new customers from

its major transmission lines in areas outside the Authority’s service area in an amount not exceeding that which

was lost by such discontinuation of service.

Palmetto Economic Development Corporation. Central and the Authority have joined together to form

a joint economic development effort, known as the Palmetto Economic Development Corporation, to benefit the

State, the Authority and Central. Formed in September 1988, it works to more effectively recruit new industries

and to increase job opportunities throughout the State. The joint operation is governed by an eight-member board

of directors, four named by Central and four named by the Authority. In February 2012, the Authority and Central

announced economic development rates for new and expanded large industrial loads to further enhance their

economic development efforts.

17
Wholesale - Other

In addition to Central, the Authority provides wholesale electric service to the City of Georgetown, the

City of Bamberg, and SCE&G pursuant to long-term contracts. New service agreements were executed in 2013

with the City of Georgetown and the City of Bamberg for 10 years and 20 years, respectively. Sales to these

customers and off-system sales to other utilities and power marketers during 2013 represented approximately 1.2%

of revenues from sales.

The Authority has a long-term power agreement with Piedmont Municipal Power Agency (“PMPA”)

pursuant to which the Authority provides PMPA its supplemental electric power and energy requirements (ranging

from approximately 200 MW to 300 MW) above its current resources. This agreement commenced on January

1, 2014, for a term of no less than 12 years.

The Authority also has an agreement pursuant to which it provides Alabama Municipal Electric Authority

50 MW unit-contingent capacity and associated energy (25 MW-50 MW). This agreement commenced on January

1, 2014, for a term of 10 years.

Direct Retail Service Area

The Authority owns distribution facilities and serves in two non-contiguous areas covering portions of

Berkeley, Georgetown and Horry Counties. These service areas include 2,787 miles of distribution lines. The

following table presents retail customer growth from 2009 through 2013 in these areas.

Retail Customers

 Year Residential

Commercial

and

Small Industrial Total 

 Annual

 Increase % 

 2009 133,229 29,752 162,981 0.2

 2010 134,704 28,897 163,601 0.4

 2011 136,047 28,600 164,647 0.6

 2012 138,353 28,456 166,809 1.3

 2013 140,126 28,687 168,813 1.2

Sales to residential, commercial, small industrial customers and certain other customers are made pursuant

to rate schedules established from time to time by the Authority. The vast majority of such rate schedules include

monthly automatic fuel adjustment and demand sales adjustment clauses. Sales to this customer group represented

approximately 19.8% of revenues from sales in 2013.

Large Industrial Contracts

Sales to large industrial customers are made pursuant to long-term contracts. The Authority offers a large

power rate schedule prepared on a cost of service basis for large industrial customers which contract for a minimum

of 1,000 kilowatts (“kW”). The Authority requires that such customers enter into contracts for initial periods of

not less than five years. All contracts contain rate provisions of the demand and energy type, and include monthly

automatic fuel adjustment and demand sales adjustment clauses, minimum demand charges and other provisions

generally used in large industrial power rate schedules. The average cost per kWh varies depending upon the

customer's usage and load factor.

Sales to large industrial customers during 2013 represented approximately 21.2% of revenues from sales,

which includes 8.9% for Alumax of South Carolina, Inc. (“Alumax”), 5.0% for Nucor Corporation (“Nucor”), and

5.2% for the next eight largest industrial customers, of which no one customer represents more than 1.5% of sales. 

Of the 21.2% of revenues from sales, approximately 66.8% represents fuel cost recovery.

Long-Term Power Contract with Alumax. The Authority has a long-term power contract with Alumax

which extends through December 31, 2015. The contract provides for the delivery of approximately 400 MW of

power under three different rate schedules or riders. Approximately 25% of the load is currently served under the

Authority’s firm industrial rate schedule, with the majority of the remainder served under the supplemental

curtailable schedule. A small portion of the load is served under the interruptible rate schedule. Alumax’s

obligations under the contract are guaranteed by its parent company, Alcoa, Inc. The contract contains a provision

that Alumax must notify the Authority by June 30, 2014 if it intends to cease operations after December 31, 2015. 

18
In addition to its standard termination provisions, the contract contains a provision that allows for early termination

if certain conditions based on the price of aluminum are met. At this time, conditions have been met that would

allow Alumax to terminate the contract with six months prior notice, but Alumax has not given the Authority notice

it intends to exercise its right to terminate.

Long-Term Power Contract with Nucor. The Authority has a long-term power contract with Nucor which

extends through April 30, 2015 and provides for two year rollover terms thereafter. The contract currently provides

for delivery of approximately 300 MW of power, the majority of which is provided under the interruptible rate

schedule.

RATES AND RATE COMPARISON

Rates

The Authority's Board of Directors is empowered and required to set rates as necessary to provide for

expenses, including debt service, of the Authority. The Authority monitors rates and management recommends

adjustments as necessary. On September 11, 2012, the Authority’s Board of Directors approved a series of two

base rate adjustments for its retail, industrial and municipal customers. The adjustments increased total charges

for customers an average 3.5 percent each year for a total increase of 7 percent to ensure rates are at least adequate

to provide revenues sufficient to pay debt service, the cost of operation and maintenance of the Authority’s System,

and meet the Revenue Obligation requirements for transfers to the Capital Improvement Fund, and all other such

costs as necessary. The first adjustment took effect December 1, 2012 and the second took effect on December

1, 2013.

The Authority has developed and offers time-of-use, non-firm and off-peak rates to its direct-served

commercial and industrial customers to encourage them to reduce their peak demand. As of December 31, 2013,

the Authority had 834 MW of non-firm power under contract. The Authority also has seasonal energy charges for

most rates affecting residential, commercial, and industrial customers. Seasonal energy charges reflect higher

charges during the summer months when higher energy costs are incurred. The Authority's rate schedules include

monthly automatic fuel adjustment clauses which provide for increases or decreases to the basic rate schedules to

cover increases or decreases in the cost of fuel to the extent such costs vary from a predetermined base cost. The

Authority's rate schedules also include a demand sales adjustment clause which provides for increases or decreases

to the basic rate schedules to reflect increases or decreases in demand revenues from non-firm sales (such as

supplemental curtailable, interruptible and economy power rate schedules and riders) and off-system sales to the

extent such revenues vary from predetermined amounts included as credits to firm base rates. For a more detailed

discussion of the Central Agreement see “CUSTOMER BASE - Wholesale - Central.”

Rates under the Central Agreement, as amended, are determined in accordance with the cost of service

methodology contained in the Central Agreement. Under the Central Agreement, Central initially pays for its

power supply based on the Authority’s projected costs and loads. The charges are then adjusted, on an annual

basis, to reflect actual costs and load and Central is charged or credited the difference between the amounts paid

based on projected rates and the amounts due based on actual rates.

During 2013 revenues from sales to wholesale requirements customers averaged 6.95 cents per kWh,

revenues from sales to large industrial customers averaged 5.14 cents per kWh, and revenues from sales to

residential, commercial, small industrial and other customers averaged 9.63 cents per kWh based on the then

current rates which included fuel adjustments and credits for demand sales adjustments.

Rate Comparison

The Authority has seasonal rates for the majority of its residential, commercial, and industrial customers. 

Comparisons of the Authority’s average monthly bills for firm service at selected usage levels with the average

monthly bills of the three investor-owned utilities that serve the State based on rates on file with the South Carolina

Public Service Commission (the “PSC”) as of July 31, 2013 and January 31, 2014 are set forth on the following

page.

19
As of July 31, 2013 (Summer)

 Residential Electric Service 

500

 kWh 

1,000

 kWh 

2,000

 kWh 

3,000

 kWh 

Authority . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $62.14 $112.27 $212.54 $312.81

Duke Energy Carolinas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51.12 94.96 190.86 286.76

Duke Energy Progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56.36 106.21 205.92 305.63

SCE&G . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73.72 140.53 281.90 423.27

 Commercial Electric Service 

3,000

 kWh 

5,000

 kWh 

7,500

 kWh 

Authority . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $288.81 $471.35 $699.53

Duke Energy Carolinas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 256.32 423.58 610.34

Duke Energy Progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 307.28 463.84 659.54

SCE&G . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 391.05 655.55 986.18

 Industrial Electric Service 

1,000 kW

500,000

 kWh 

2,000 kW

1,000,000

 kWh 

 9,000 kW 

 5,000,000

 kWh 

40,000 kW

25,000,000

 kWh 

Authority . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $37,421.47 $72,042.94 $334,941.23 $1,593,138.80

Duke Energy Carolinas . . . . . . . . . . . . . . . . . . . . 28,270.04 53,635.52 253,421.54 1,244,112.57

Duke Energy Progress . . . . . . . . . . . . . . . . . . . . . 37,035.00 73,645.00 351,605.00 1,656,725.00

SCE&G . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41,870.00 81,815.00 386,615.00 1,851,575.00

As of January 31, 2014 (Non-Summer)

 Residential Electric Service 

500

 kWh 

1,000

 kWh 

2,000

 kWh 

3,000

 kWh 

Authority . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $60.55 $107.10 $200.20 $293.30

Duke Energy Carolinas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57.28 106.26 210.43 314.60

Duke Energy Progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56.36 104.21 193.92 283.63

SCE&G . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76.06 141.05 267.88 394.71

 Commercial Electric Service 

3,000

 kWh 

5,000

 kWh 

7,500

 kWh 

Authority . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $269.70 $437.50 $647.25

Duke Energy Carolinas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 274.74 453.65 654.61

Duke Energy Progress . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 307.28 463.84 659.54

SCE&G . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 404.20 641.62 938.40

 Industrial Electric Service 

1,000 kW

500,000

 kWh 

2,000 kW

1,000,000

 kWh 

 9,000 kW 

 5,000,000

 kWh 

40,000 kW

25,000,000

 kWh 

Authority . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $35,841.44 $68,682.88 $315,617.96 $1,487,107.60

Duke Energy Carolinas . . . . . . . . . . . . . . . . . . . . 32,294.00 61,571.90 291,094.00 1,418,608.10

Duke Energy Progress . . . . . . . . . . . . . . . . . . . . . 37,035.00 73,645.00 351,605.00 1,656,725.00

SCE&G . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43,050.00 84,125.00 397,605.00 1,904,525.00

20
POWER SUPPLY AND POWER MARKETING

Existing Generating Facilities

The Authority's generating facilities consist of the following facilities:

 Generating Facilities(1) Location 

Initial 

Date in

Service

Winter

MCR(2)

 (MW) 

Summer

MCR(2)

 (MW) 

Energy 

Source 

Jefferies Hydroelectric Generating

 Station . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Moncks Corner 1942 127 127 Hydro

Wilson Dam Generating Station . . . . . . . . . . . . . . Lake Marion 1950 2 2 Hydro

Jefferies Generating Station . . . . . . . . . . . . . . . . . Moncks Corner

 Nos. 1 and 2(3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1954 88 84 Oil

Combustion Turbines Nos. 1 and 2 . . . . . . . . . . . . Myrtle Beach 1962 20 16 Oil/Gas

Combustion Turbines Nos. 3 and 4 . . . . . . . . . . . . Myrtle Beach 1972 40 38 Oil

Combustion Turbine No. 5 . . . . . . . . . . . . . . . . . . Myrtle Beach 1976 25 21 Oil

Combustion Turbine No. 1 . . . . . . . . . . . . . . . . . . Hilton Head Island 1973 20 19 Oil

Combustion Turbine No. 2 . . . . . . . . . . . . . . . . . . Hilton Head Island 1974 20 19 Oil

Combustion Turbine No. 3 . . . . . . . . . . . . . . . . . . Hilton Head Island 1979 60 52 Oil

Winyah Generating Station . . . . . . . . . . . . . . . . . . Georgetown

 No. 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1975 280 275 Coal

 No. 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1977 290 285 Coal 

 No. 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1980 290 285 Coal

 No. 4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1981 290 285 Coal

Summer Nuclear Unit 1(4) . . . . . . . . . . . . . . . . . . Jenkinsville 1983 318(5) 318(5) Nuclear

Cross Generating Station . . . . . . . . . . . . . . . . . . . . Cross

 Unit 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1995 590 580 Coal

 Unit 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1983 585 570 Coal

 Unit 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2007 600 600 Coal

 Unit 4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2008 600 600 Coal

Horry Landfill Gas Station . . . . . . . . . . . . . . . . . . Conway 2001 3 3 LMG(6)

Lee County Landfill Gas Station . . . . . . . . . . . . . . Bishopville 2005 11 11 LMG

Richland County Landfill Gas Station . . . . . . . . . Elgin 2006 8 8 LMG

Anderson County Landfill Gas Station. . . . . . . . . Belton 2008 3 3 LMG

Georgetown County Landfill Gas Station . . . . . . . Georgetown 2010 1 1 LMG

Berkeley County Landfill Gas Station . . . . . . . . . Moncks Corner 2011 3 3 LMG

Rainey Generating Station . . . . . . . . . . . . . . . . . . . Starr

 Unit 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2002 520 460 Gas

 Unit 2A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2002 180 146 Gas

 Unit 2B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2002 180 146 Gas

 Unit 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2004 90 75 Gas

 Unit 4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2004 90 75 Gas

 Unit 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2004 90 75 Gas

 Total Capability 5,424 5,182 

_________ 

(1) Grainger Generating Station Nos. 1 and 2 and Jefferies Generating Station Nos. 3 and 4 were retired on December 31, 2012.

(2) Maximum Continuous Ratings (“MCR”).

(3) These units will be retired within a timeline to be determined by the Authority’s management and in compliance with applicable 

 regulatory deadlines.

(4) Virgil C. Summer Nuclear Generating Station Unit 1 (“Summer Nuclear Unit 1”).

(5) Represents the Authority's one-third ownership interest.

(6) Landfill Methane Gas (“LMG”).

21
Existing Power Resources

The Authority plans for firm power supply from its own generating capacity and firm power contracts to

equal its firm load, including a 15% summer reserve margin. The Authority’s current total summer MCR of its

owned generating capacity is set forth in the table below. The Authority presently receives 84 MW of firm supply

from the U.S. Army Corps of Engineers (the “Corps”) and 319 MW of firm hydroelectric power from SEPA. The

SEPA allocation consists of 184 MW for wheeling to the SEPA preference customers served by the Authority and

135 MW purchased by the Authority for its customers. The Authority also receives 8 MW of dependable

capability from the Buzzards Roost hydro electric generating facility which it leases from Greenwood County,

South Carolina and 75 MW of biomass capacity and associated energy under four power purchase agreements (the

first commenced in September 2010 and the most recent in November 2013, with varying terms from 15 to 30

years). There is also an agreement to purchase the output from a 2.5 MW solar photovoltaic facility that started

producing power in December of 2013 and has a 20 year term. In addition, for the time period January 2011

through December 2014, the Authority has entered into an agreement with TEA for the purchase of unit-contingent

power from a Southern Power Company simple cycle combustion turbine resource. This purchase is anticipated

to provide a summer capability amount of 155 MW. The Authority has also entered into a purchase agreement with

JP Morgan Ventures Energy Corporation for 300 MW of capacity and associated energy beginning June 1, 2012

and continuing through December 31, 2015. The electric generation, transmission and distribution facilities owned

by the Authority as well as certain transmission facilities leased from Central, are operated by the Authority as a

fully integrated electric system. The Authority has direct interconnections with five entities, including all those

with which the Authority has long-term power contracts for energy interchange. See “POWER SUPPLY AND

POWER MARKETING -- Interconnections and Interchanges.”

The table below details the Authority's resources classified by energy source for the summer power supply

peak capability.

Source of Power Supply (MW) % of Total

Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,480 57.2

Natural Gas and Oil . . . . . . . . . . . . . . . . . . . 1,226 20.1

Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 318 5.2

Owned Hydro Generation . . . . . . . . . . . . . . 129 2.1

Landfill Methane Gas . . . . . . . . . . . . . . . . . . 29 0.5

Total MCR . . . . . . . . . . . . . . . . . . . . . . . . . . 5,182

Purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . 904 14.9

Total MCR and Purchases . . . . . . . . . . . . . . 6,086 100.00

The following table sets forth performance indicators for the Authority’s coal-fired generation for the

years 2011 through 2013.

 2011 2012 2013

Capacity Factor - % . . . . . . . . . . . . . . . . . . . 57.9 45.7 43.6

Availability Factor - % . . . . . . . . . . . . . . . . . 88.7 94.5 92.5

Forced Outage Rate - % . . . . . . . . . . . . . . . . 5.9 2.3 1.8

Net Heat Rate (BTU/kWh) . . . . . . . . . . . . . . 9,987 9,854 9,999

Performance monitoring systems are in place at the Authority’s coal-fired generating stations and at its

Rainey Generating Station to optimize each unit’s operation while complying with environmental requirements.

All Authority operated units are maintained with computerized maintenance management systems and

the use of preventive, predictive, and proactive maintenance practices to achieve high reliability and efficiency at

low maintenance cost. In its maintenance program, the Authority utilizes technologies such as vibration analysis,

oil analysis, thermography, laser alignment, and non-destructive testing. The Authority continues to implement

equipment maintenance programs for the units including major unit components such as control systems, steam

generators, and turbine generators. See “CAPITAL IMPROVEMENT PROGRAM.”

22
Summer Nuclear Unit 1. The Authority owns a one-third undivided interest in Summer Nuclear Unit 1

which has a pressurized water reactor with a maximum dependable rating of 954 MW net. SCE&G owns the

remaining two-thirds interest and operates and maintains Summer Nuclear Unit 1 on its own behalf and as the

Authority's agent.

The following table sets forth certain performance indicators for Summer Nuclear Unit 1 for the years

2011 through 2013 and for the period of commercial operation, January 1, 1984 through December 31, 2013. The

next 18 month refueling outage is scheduled to commence on April 4, 2014.

 2011(1) 2012(2) 2013 

January 1, 1984- 

December 31, 2013

 Net Generation -- MWh 7,426,233 7,281,603 8,369,878 204,331,133

 Capacity Factor -- % 87.8 85.8 98.9 83.6

 Availability Factor -- % 87.1 84.9 97.0 85.3

 Forced Outage Rate -- % 0.7 0.0 0.0 2.4

_________

(1) Spring 2011 - 45 day for scheduled refueling outage

(2) Fall 2012 - 56 day for scheduled refueling outage

The Nuclear Regulatory Commission (the “NRC”) oversees plant performance through the Reactor

Oversight Process (“ROP”) assessment program. The ROP assessment program collects information from

inspections and performance indicators (“PIs”) which the NRC uses to objectively assess a facility’s safety

performance. The ROP consists of three key strategic performance areas: Reactor Safety, Radiation Safety, and

Safeguards. Results for inspections and PIs are classified as green, yellow, white or red, with green being the most

favorable. Through the fourth quarter of 2013, Summer Nuclear Unit 1 is in the Licensee Response Column of

the ROP Action Matrix because all inspection findings had very low (i.e., green) safety significance, and all PIs

indicated that performance was within the nominal, expected range (i.e., green). As a result of being in the

Licensee Response Column, NRC oversight of Summer Nuclear Unit 1 is limited to baseline inspections.

In 2004, the NRC extended the operating license for Summer Nuclear Unit 1 to August 6, 2042, which

was an additional twenty years.

Under the provisions of the Nuclear Waste Policy Act of 1982, on June 29, 1983 SCE&G and the

Authority entered into a contract (the “Standard Contract”) with the DOE for spent fuel and high level waste

disposal for the operating life of Summer Nuclear Unit 1. The Nuclear Waste Policy Act and the Standard

Contract required the DOE to accept and dispose of spent nuclear fuel and high-level radioactive waste beginning

not later than January 31, 1998. To date, the DOE has accepted no spent fuel from Summer Nuclear Unit 1 or any

other utility, and has not indicated when it anticipates doing so. 

Summer Nuclear Unit 1 has licensed on-site spent fuel storage capability until 2017 while still maintaining

full core discharge capability. In 2013, construction began on a dry cask storage facility to accommodate the spent

nuclear fuel output for the life of Summer Nuclear Unit 1. The dry cask storage facility will be available to receive

spent nuclear fuel in 2015.

Unit Retirements. After evaluating the costs of complying with newly adopted federal regulations and

the foreseeable generation resource needs for the Authority’s system, management determined it would not be cost

effective to implement the new environmental measures that would be necessary for continued operation of certain

units. In 2012, the Authority’s Board of Directors authorized retirement of six electric generating units: Grainger

Generating Station Nos. 1 and 2, and Jefferies Generating Station Nos. 1, 2, 3 and 4. The Board authorized the

President and CEO to develop and execute plans for an orderly retirement of the four coal and two oil units. 

Grainger Generating Station Nos. 1 and 2 and Jefferies Generating Station Nos. 3 and 4 ceased operations and were

officially retired on December 31, 2012. Appropriate notifications were submitted to the federal Environmental

Protection Agency (the “EPA”) and The South Carolina Department of Health and Environmental Control (the

“DHEC”) to modify existing Title V air operating permits to reflect the cease operation of those units. Jefferies

Generating Station Nos. 1 and 2 will be retired within a timeline to be determined by the Authority’s management

and in compliance with applicable regulatory deadlines. 

23
Renewable Energy Power Purchase Agreements. The Authority has purchase power agreements for

approximately 25 MW of biogas-fueled energy from multiple facilities within the State. Commercial operations

for these facilities are scheduled over the next six years.

Transmission

The Authority operates an integrated transmission system which includes lines owned and leased by the

Authority as well as those owned by Central. The transmission system includes approximately 1,265 miles of 230

kilovolt (“kV”), 1,834 miles of 115 kV, 1,733 miles of 69 kV, 10 miles of 46 kV and 97 miles of 34 kV and below

overhead and underground transmission lines. The Authority operates 105 transmission substations and switching

stations serving 85 distribution substations and 465 Central Cooperative delivery points. Monitoring and control

of integrated power system operations is supported by 91 primary communications sites. The Authority plans the

transmission system to operate during normal and contingency conditions that are outlined in electric system

reliability standards adopted by the North American Electric Reliability Corporation (“NERC”) and to maintain

system voltages that are consistent with good utility practice.

Interconnections and Interchanges

The Authority's transmission system is interconnected with other major electric utilities in the region. It

is directly interconnected with SCE&G at eight locations; with Duke Energy Progress at eight locations; with

Southern Company Services, Inc. (“Southern Company”) at one location; and with Duke Energy Carolinas, at two

locations. The Authority is also interconnected with SCE&G, Duke Energy Carolinas, Southern Company and

SEPA through a five-way interconnection at SEPA's J. Strom Thurmond Hydroelectric Project, and with Southern

Company and SEPA through a three-way interconnection at SEPA's R. B. Russell Hydroelectric Project. Through

these interconnections, the Authority's transmission system is integrated into the regional transmission system

serving the southeastern areas of the United States and the Eastern Interconnection. The Authority has separate

interchange agreements with each of the companies with which it is interconnected which provide for mutual

exchanges of power.

Reliability Agreements

The Authority is a party to the Virginia-Carolinas Reliability Agreement (“VACAR”) which exists for

the purpose of safeguarding the reliability of electric service of the parties thereto. Other parties to the VACAR

agreement are SCE&G, Duke Energy Progress, Duke Energy Carolinas, APGI-Yadkin Division, Dominion

Virginia Power, and Public Works Commission of the City of Fayetteville.

The Authority is also a member of the SERC Reliability Corporation, which is one of 8 regional entities

under the NERC.

Distribution

The Authority owns distribution facilities in two service areas: the Berkeley District serving retail

customers in St. Stephen, Bonneau Beach, Moncks Corner and Pinopolis; and the Horry-Georgetown Division

serving retail customers in Conway, Myrtle Beach, North Myrtle Beach, Loris, Briarcliffe, Surfside Beach, Atlantic

Beach, Pawleys Island, unincorporated areas along the Grand Strand and portions of rural Georgetown and Horry

Counties. See “CUSTOMER BASE.”

General Plant

The Authority owns general plant consisting of office facilities; transportation and heavy equipment;

computer equipment; and communication equipment necessary to support the Authority's operations. The

Authority has nine customer service offices throughout its direct service territory and corporate headquarters

located in Moncks Corner which includes a garage, maintenance facilities and warehouse facilities.

24
Fuel Supply

During 2013, the Authority's energy supply, including energy wheeled to SEPA preference customers,

was derived as set forth in the following table. 

Source of Power Supply

% of Total

(MWh) 

Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51.1

Natural Gas and Oil . . . . . . . . . . . . . . . . . . . 15.8

Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2

Owned Hydro Generation . . . . . . . . . . . . . . 2.3

Purchases . . . . . . . . . . . . . . . . . . . . . . . . . . . 20.2

Landfill Methane Gas . . . . . . . . . . . . . . . . . . 0.4

Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100.0

Coal. The Authority has contracted for bituminous coal for its Winyah and Cross Generating Stations

from a number of companies, and additional coal is acquired from spot market purchases. All of the Authority's

suppliers have loading facilities for providing delivery of coal in unit train shipments. The Authority owns 1,711

coal cars and periodically supplements its fleet with cars provided by the railroad and through short term leases. 

Currently, the Authority has 106 cars on short term lease. The Authority’s current rail transportation contract

extends through 2015. 

The Authority contracts for solid fuel from three primary coal basins: Central Appalachia, Northern

Appalachia, and Illinois Basin. Considering quantity and quality requirements, the Authority uses a combination

of these coal supplies with long-term and short-term contracts to meet its solid fuel needs. The Authority evaluates

the fuel contracts based on the lowest delivered prices while ensuring and adapting to future needs. 

The Authority uses a methodology that reflects the impact of coal to gas switching to calculate its coal

days on hand. This methodology for calculating coal days on hand uses the annual amount of coal budgeted to be

burned divided by 365. The annual burn budget uses projections based on gas prices and forward price curves

available at the time the budget is developed and should therefore factor in coal to gas generation switching based

on economics. Using this methodology, the Authority had 224 days of coal on hand as of December 31, 2013. 

In terms of tonnage, as of December 31, 2013, the Authority had approximately 4.40 million tons of coal on hand. 

Sulfur dioxide (“SO2”) air emission limitations dictate the maximum amount of coal sulfur content that

can be used by generating units. The sulfur content of coal received under existing contracts ranges from

approximately 0.9% to 3.0%. The Authority believes it can obtain an adequate coal supply with sulfur content

within acceptable ranges to meet foreseeable needs. See “REGULATORY MATTERS -- Environmental Matters.”

Gas. The Authority has contracted with Transcontinental Gas Pipeline Corporation to provide firm gas

transportation in an amount approximately equal to the Rainey Generating Station combined cycle unit at full load. 

Any additional gas transportation necessary to fuel the remaining needs of the simple cycle units at the

station will be purchased on the spot market as needed. If gas is unavailable or uneconomical, the Authority will

operate the station using fuel oil where possible. The Authority has backup oil storage facilities on site.

The Authority purchases the majority of its natural gas on a daily or short-term basis and does not

currently have any purchases under long term agreements. The Authority’s natural gas risk is managed using a

financial hedge strategy. See “POWER SUPPLY AND POWER MARKETING -- Fuel Supply -- Commodity Risk

Management.” All of the Authority’s natural gas transactions are currently executed by TEA. 

25
Commodity Risk Management. The Authority’s Board of Directors has approved a policy that deals with

the philosophy, framework and delegation of authority necessary to govern the activities related to the Authority’s

commodity risk management program. The Authority strives to mitigate variations in price with a combination

of long-term and short-term contracts, a fuel commodity risk hedging program, and by taking advantage of market

opportunities, such as purchasing and blending off-specification coal when the economics are favorable. 

The Authority has determined that all transactions executed under the policy will be executed through

TEA.

Nuclear. Under the Joint Ownership Agreement for Summer Nuclear Unit 1, SCE&G acts for itself and

as agent for the Authority in the operation of Summer Nuclear Unit 1 including the acquisition and management

of nuclear fuel. Contracts are in place to supply uranium and conversion through 2020. Enrichment services will

be met by contract through 2024. 

The Energy Authority

The Authority is a member of TEA along with City Utilities of Springfield (Missouri), Gainesville

Regional Utilities (Florida), Jacksonville Energy Authority (“JEA”), Municipal Electric Authority of Georgia 

(“MEAG Power”), Nebraska Public Power District (“NPPD”), Public Utility District No. 1 of Cowlitz County,

Washington and American Municipal Power.

TEA markets wholesale power and coordinates the operation of the generation assets of its members to

maximize the efficient use of electrical energy resources, reduce operating costs and increase operating revenues

of its members. TEA is expected to accomplish the foregoing without impacting the safety and reliability of the

electric system of each member. In addition, TEA purchases and sells natural gas relating to fuel for members’

generation of electricity. TEA does not engage in the construction or ownership of generation or transmission

assets.

The standards of conduct provisions of Order 717 of the Federal Energy Regulatory Commission (the

“FERC”) require that employees of a utility engaged in transmission system operations function independently

of employees of the utility or any of its affiliates who are engaged in the wholesale merchant function. The

Authority believes that the establishment of TEA assists in satisfying that requirement. 

All of TEA’s revenues and its costs are allocated to its members. The Authority's exposure relating to

TEA is limited to the Authority’s capital investments in TEA, any accounts receivable from TEA and trade

guarantees provided to TEA by the Authority.

The current amount approved by the Authority to support TEA’s trading and procurement activities is an

amount not to exceed approximately $72.9 million. If payment is required to be made, it will be treated as an

operation and maintenance expense.

Colectric Partners

The Authority is also a member of Colectric Partners (“Colectric”). Colectric’s member participants are:

the Authority, Florida Municipal Power Agency, Gainesville Regional Utilities, JEA, MEAG Power, NPPD and

Orlando Utilities Commission. 

Colectric is a membership-driven nonprofit corporation headquartered in Jacksonville, Florida which

serves the public power industry in a variety of project and business management roles. They help their members

leverage economies of scale to control operations and maintenance costs and streamline power generation projects. 

Currently, the Authority participates in two of Colectric’s initiatives. The first involves managing the

major gas turbine overhauls, thereby promoting the sharing of spare parts and technical expertise. The second

initiative is a strategic sourcing initiative, intended to achieve major cost savings through volume purchasing

leverage. 

26
CAPITAL IMPROVEMENT PROGRAM

General

The Authority regularly reviews and updates its capital improvement program to reflect currently

projected capital projects and expenditures. Total cost of the capital improvement program for 2014 through 2016

is estimated to be approximately $2,724,000,000, which includes approximately $2,056,000,000 for Summer

Nuclear Units 2 and 3 based on 45% ownership, approximately $167,000,000 for environmental compliance

expenditures, and approximately $501,000,000 for general improvements to the System. See “FINANCING PLAN

FOR SUMMER NUCLEAR UNITS 2 AND 3" for further details. The Authority typically finances generation

resources and large capital projects with long-term borrowed funds while utilizing the capital improvement fund

for other resources such as general improvements to the System and equity to reduce taxable borrowings. The cost

of the capital improvement program will be provided from Revenues of the Authority, additional Revenue

Obligations, and Commercial Paper Notes and other short-term obligations of the Authority, as determined by the

Authority. 

Long-Term Power Supply Plan

The Authority's overall power supply objective is to continue to satisfy the electric power and energy

needs of its customers with economical and reliable service. As part of this objective the Authority strives to have

in place a diverse power supply that utilizes a variety of fuel sources. The Authority reviews, from time to time,

its power resources and requirements and considers the need for the possible addition of new power resources, the

retirement of existing resources and other modifications to its resource plan. In January 2008, the Authority’s

Board of Directors approved a generation resource plan that included, among other things, a 45% ownership

interest in Summer Nuclear Units 2 and 3. These units are projected to increase the percentage of power generated

from nuclear resources from approximately 8.35% to approximately 42.17% after both units are completed. Nuclear

power stations have higher capital costs, but they have very low fuel costs, which have already proven to be stable

and competitive, to balance out the capital expense. Nuclear power is an emissions free, non-greenhouse gas

emitting resource and, therefore is not subject to regulation and legislation typically associated with fossil fired

resources such as those targeting carbon and SO2 emissions.

The Authority has evaluated its capital improvement program and long-term power supply plan in light

of the on-going economic downturn, the reduction in previously anticipated sales to Central, as described under 

“CUSTOMER BASE - Wholesale,” and new EPA regulations which increase the operating costs of coal-fired

generating units as described under “REGULATORY MATTERS -- Environmental Matters.” As a result, the

Authority will retire six electric generating units (See “POWER SUPPLY AND POWER MARKETING-- Existing

Power Resources”) and has entered into an agreement whereby SCE&G would purchase an additional 5% in

Summer Nuclear Units 2 and 3. Under the terms of the agreement, SCE&G will own 60% of the new nuclear units

and the Authority, 40%. See CAPITAL IMPROVEMENT PROGRAM -- Summer Nuclear Units 2 and 3.” 

27
Summer Nuclear Units 2 and 3

Technology. Summer Nuclear Units 2 and 3 will consist of two Westinghouse AP1000 nuclear reactors,

four low profile sixteen-cell mechanical draft cooling towers, intake and discharge structures, a 230 kV switchyard

for transmission access, and numerous ancillary structures supporting the power generation process. 

On January 27, 2006, the NRC approved the AP1000 standard plant design and issued its original AP1000

Design Certification Rule (“DCR”) which incorporated Revision 15 of the AP1000 Design Control Document

(“DCD”).

On December 30, 2011, the NRC amended its regulations to certify an amendment to the AP1000 standard

plant design incorporated in DCD Revisions 16 through 19. The amendment replaces the combined license

information items and design acceptance criteria (“DAC”) with specific design information, addresses the effects

of the impact of a large commercial aircraft, incorporates design improvements, and increases standardization of

the design.

The AP1000 is the first and only reactor in its class of technological development, referred to as

“Generation III+”, to receive certification from the NRC. 

28
The AP1000 is a pressurized water reactor with passive safety systems which, according to Westinghouse, in case

of design basis accidents are designed to achieve a safe shutdown without operator action, AC power, or pumps.

Licensing. In March 2008, the Authority and SCE&G submitted to the NRC an application for Combined

Construction and Operating Licenses ("COLs") for Summer Nuclear Units 2 and 3. On March 30, 2012, the NRC

concluded its mandatory hearing process for the application and found the NRC staff’s review adequate to make

the necessary regulatory safety and environmental findings, clearing the way for the formal issuance of the COLs. 

The COLs were issued by the NRC and received by SCE&G and the Authority on March 30, 2012.

The NRC’s findings concluding the mandatory hearing process imposed two conditions on the COLs, with

the first requiring inspection and testing of squib valves, important components of the reactor’s passive cooling

system. The second requires the development of strategies to respond to extreme natural events resulting in the

loss of power at the new reactors. The NRC also directed the Office of New Reactors to issue to SCE&G and the

Authority, simultaneously with the COLs, an Order requiring enhanced, reliable spent fuel pool instrumentation,

as well as a request for information related to emergency plant staffing. 

Engineering, Procurement, and Construction Agreement. On May 23, 2008, SCE&G, acting for itself

and as agent for the Authority, entered into an Engineering, Procurement, and Construction ("EPC") Agreement,

with a Consortium consisting of Westinghouse Electric Company, LLC and Stone & Webster, Inc. Pursuant to

the EPC Agreement, the Consortium will supply, construct, test, and start up two 1,117 MW nuclear generating

units utilizing Westinghouse’s AP1000 standard plant design. Under the EPC Agreement, the Authority will pay,

in proportion to its ownership interest, a contract price that is subject to certain fixed price escalations and

adjustments, adjustments for change orders and performance bonuses, and adjustments for cost overruns. A

majority of the EPC Agreement costs are fixed or firm. In addition to EPC Agreement costs, the Authority will

pay, in proportion to its ownership interest, costs associated with ancillary project facilities, staffing, project

management and oversight by SCE&G and the Authority. The Authority estimates the current total construction

cost associated with a 45% ownership interest to be approximately $5.1 billion including related transmission and

initial nuclear fuel cores.

The EPC Agreement provides the Authority and SCE&G are jointly and severally liable for obligations

under the EPC Agreement, to the extent such joint and several liability does not conflict with State law applicable

to the Authority. Current State law provides the Authority shall be severally liable, in proportion to its joint

ownership interest, for the acts, omissions, obiligations performed, omitted, or incurred by SCE&G acting as agent

for the Authority in constructing, operating or maintaining the Summer Units, but is not otherwise liable, jointly

or severally for SCE&G's acts or omissions. 

The EPC Agreement provides for certain liquidated damages upon the Consortium’s failure to comply

with schedule and performance guarantees, as well as certain bonuses payable to the Consortium for unit

performance. The Consortium’s liability for liquidated damages and for warranty claims is subject to a cap. The

payment obligations of Westinghouse are guaranteed by Toshiba Corporation, and the payment obligations of

Stone & Webster are guaranteed by Chicago Bridge & Iron Company. The Authority and SCE&G may, at any

time, terminate the EPC Agreement for their convenience and without cause, provided that the Authority and

SCE&G will pay certain termination costs and, at certain stages of the work, termination fees to the Consortium. 

The Consortium may terminate the EPC Agreement under certain circumstances, including (i) either SCE&G or

the Authority’s failure to make payment to Consortium in accordance with the EPC Agreement requirements, (ii)

either SCE&G or the Authority’s breach of a material provision of the EPC Agreement, or (iii) either SCE&G or

the Authority’s insolvency unless the other of SCE&G or the Authority has provided security for payments that

would be due from such insolvent entity.

Ownership Agreements. On October 20, 2011, the Authority and SCE&G entered into a Design and

Construction Agreement specifying an Authority ownership interest of 45% in each of Summer Nuclear Unit 2 and

Summer Nuclear Unit 3. Among other things, the Design and Construction Agreement allows either or both parties

to withdraw from the project under certain circumstances. Also on October 20, 2011, the Authority and SCE&G

entered into an Operating and Decommissioning Agreement with respect to the two units. Both the Design and

Construction Agreement and the Operating and Decommissioning Agreement define the conditions under which

the Authority or SCE&G may convey an undivided ownership interest in the units to a third party.

In January, 2014, the Authority's negotiations with Duke Energy Carolinas to purchase a portion of the

Authority's ownership interest in Summer Nuclear Units 2 and 3 terminated. Subsequently, the Authority entered

into an agreement whereby SCE&G would purchase an additional 5% in the units. Under the terms of the

agreement, SCE&G will own 60% of the new nuclear units and the Authority, 40%. The 5% ownership interest

29
would be acquired in three stages, with 1% to be acquired at the commercial operation date of the first new nuclear

unit, which is anticipated to be in late 2017 or the first quarter of 2018, an additional 2% to be acquired no later

than the first anniversary of such commercial operation date and the final 2% to be acquired no later than the

second anniversary of such commercial operation date. The purchase price would be equal to the Authority's actual

cost, including financing costs, of the percentage conveyed as of the date of the conveyance. The Authority is

exploring opportunities to market capacity from the units to potential buyers.

Construction - Phase I. Phase I of the work consists of the Consortium’s engineering support and other

services required by SCE&G and the Authority to support licensing efforts for Summer Nuclear Units 2 and 3

(including receipt of approvals from the PSC), continuation for design work, project management, engineering and

administrative support to procure long lead time equipment, construction mobilization, site preparation, site

infrastructure development, and installation of construction facilities. Phase I commenced May 23, 2008, with

execution of the EPC Agreement, and was completed April 17, 2012 with SCE&G and the Authority’s issuance

of Full Notice to Proceed following receipt of the COLs.

Construction - Phase II. Phase II of the work consists of the remainder of the work required to supply,

construct, test, and start up two AP1000 nuclear power plant units as is consistent with the AP1000 certified design. 

Phase II work is progressing and several key construction milestones have been achieved for Summer Nuclear

Units 2 and 3.

Units 2 & 3 - Energized Switchyard February 1, 2013

Unit 2 - Placed Nuclear Island Basemat (First Nuclear Concrete) March 11, 2013

Unit 2 - Set Module CR10 (Containment Vessel Bottom Head Support) April 3, 2013

Unit 2 - Set Containment Vessel Bottom Head May 22, 2013

Unit 2 - Set Structural Module CA01 (Reactor Vessel Cavity) September 27, 2013

Unit 3 - Placed Nuclear Island Basemat (First Nuclear Concrete) November 4, 2013

Schedule. During the course of activities under the EPC Agreement, issues have materialized that have

impacted project budget and schedule. The parties to the EPC Agreement have established both informal and

formal dispute resolution procedures to resolve issues that arise during the course of constructing a project of this

magnitude. 

Claims specifically relating to COL delays, design modifications of the shield building and certain prefabricated structural modules and unanticipated rock conditions at the site resulted in assertions of contractual

entitlement to recover additional costs to be incurred. On July 11, 2012, SCE&G, on behalf of itself and as agent

for the Authority, agreed to a settlement with the Consortium which set the Authority’s portion of the costs for

these specific claims at approximately $113 million (in 2007 dollars). As a result of this settlement, the substantial

completion dates for Summer Nuclear Units 2 and 3 changed from April 2016 and January 2019 (respectively) to

March 2017 and May 2018. 

The Consortium has experienced delays in the schedule for fabrication and delivery of sub-modules for

the new units. After examination of this issue and consultation with the Consortium, in June 2013, SCE&G

announced that the substantial completion of Summer Nuclear Unit 2 is expected to be delayed from March 2017

to late 2017 or the first quarter of 2018 and the substantial completion for Summer Nuclear Unit 3 is expected to

be similarly delayed. 

Since August 2013, the Consortium has experienced additional delays in sub-module fabrication and

deliveries but reconfirmed the substantial completion dates announced in June 2013. The fabrication and delivery

of sub-modules are a focus area of the Consortium, including sub-modules for module CA20, which is part of the

auxiliary building, and CA01, which houses components inside the containment vessel. Modules CA20 and CA01

are considered critical path items for both new units. All sub-modules for CA20 have been received on site, and

its fabrication is underway. CA20 is expected to be ready for placement on the nuclear island of the first new unit

in the second quarter of 2014. In addition, the delivery schedule of the sub-modules for CA01 is expected to

support completion of on-site fabrication to allow it to be ready for placement on the nuclear island during the

fourth quarter of 2014. In response to these additional delays, SCE&G and the Authority are actively working with

Consortium executive management to take actions necessary to maintain the substantial completion dates

announced in June 2013. 

The Authority cannot predict with certainty the extent to which the issue with the sub-modules or the

delays in the substantial completion of the new units will result in increased project costs. However, based on

SCE&G's estimate of its share of delay-related costs associated with the new units, the Authority estimates its share

30
could be approximately $150 million. This amount is within the Authority’s current approved budget and would

not result in an increase to the total budget. The Authority has not accepted responsibility for any of these delayrelated costs and will continue to work with SCE&G and the Consortium to refine this preliminary estimate, and

the Authority will have further discussions regarding responsibility for any increased costs.

In addition to the above-described project delays, the Authority is also aware of financial difficulties a

supplier responsible for certain significant components of the project is experiencing. The Consortium is

monitoring the potential for disruptions in such equipment fabrication and possible responses. Any disruptions

could impact the project's schedule or costs, and such impacts could be material.

During the fourth quarter of 2013, the Consortium began a full re-baselining of the Unit 2 and Unit 3

construction schedules to incorporate a more detailed evaluation of the engineering and procurement activities

necessary to accomplish the schedule and to provide a detailed reassessment of the impact of the revised Unit 2

and Unit 3 schedules on engineering and design resource allocations, procurement schedules, construction work

crew assignments, and other items. The result will be a revised fully integrated construction schedule that will

provide detailed and itemized information on individual budget and cost categories, cost estimates at completion

for all non-firm and fixed scopes of work, and the timing of specific construction activities and cash flow

requirements. The Authority anticipates that the revised schedule and the cost estimate at completion for all nonfirm and fixed scopes of work will be finalized in the third quarter of 2014. 

Nuclear Construction - Risk Factors. The construction of large generating plants such as Summer Nuclear

Units 2 and 3 involves significant financial risk. Delays or cost overruns may be incurred as a result of risks such

as (a) inconsistent quality of equipment, materials and labor, (b) work stoppages, (c) regulatory matters, (d)

unforeseen engineering problems, (e) unanticipated increases in the cost of materials and labor, (f) performance

by engineering, procurement, or construction contractors, and (g) increases in the cost of debt. Moreover, no

nuclear plants have been constructed in the United States using advanced designs such as the Westinghouse

AP1000 reactor. Therefore, estimating the cost of construction of any new nuclear plant is inherently uncertain. 

To mitigate risk, SCE&G, acting for itself and as agent for the Authority, provides project oversight for

Summer Nuclear Units 2 and 3 through its New Nuclear Deployment (“NND”) business unit. The Authority

provides dedicated on-site personnel to monitor and assist NND with the daily oversight of the project. The

managerial framework of the NND group is comprised of in-house nuclear industry veterans who lead various

internal departments with expertise in: nuclear operations, engineering, construction, maintenance, quality

assurance and nuclear regulations. This expertise is dispatched locally to monitor on site construction as well as

domestically (and abroad) to provide surveillance at all major equipment manufacturers. In addition, NND

representatives make frequent visits and work closely with the Consortium to monitor progress and issues

(engineering, labor, supplier issues, etc.) associated with the AP1000 nuclear power units currently under

construction in China, as well as the AP1000 units currently under development at nearby Plant Vogtle in

Waynesboro, Georgia. 

31
HISTORICAL SALES

Historical Demand, Sales and Revenues

 The following table sets forth the territorial peak demand including firm off-system sales to other utilities,

if any, on the Authority's System as well as the million kWh (“GWh”) sales and electric revenues of the Authority

for the years 2004 through 2013.

 Peak Demand(1) Sales Revenue From Sales 

Annual Annual Amount Annual Cents

Increase Increase (Dollars in Increase Per

 MW (Decrease) GWh (Decrease) Thousands) (Decrease) kWh

2004 . . . . . . . . . . . 5,111 (5.3) 24,451 1.6 1,136,042 9.9 4.65

2005 . . . . . . . . . . . 5,393 5.5 25,064 2.5 1,334,057 17.5 5.33

2006 . . . . . . . . . . . 5,218 (3.2) 25,422 1.4 1,396,252 4.6 5.49

2007 . . . . . . . . . . . 5,584 7.0 27,221 7.1 1,448,327 3.7 5.32

2008 . . . . . . . . . . . 5,672 1.6 26,687 (2.0) 1,568,618 8.3 5.88

2009 . . . . . . . . . . . 5,612 (1.1) 25,813 (3.3) 1,683,469 7.3 6.52

2010 . . . . . . . . . . . 5,762 2.7 28,182 9.2 1,875,263 11.4 6.65

2011 . . . . . . . . . . . 5,697 (1.1) 27,552 (2.2) 1,894,847 1.0 6.88

2012 . . . . . . . . . . . 5,407 (5.1) 26,756 (2.9) 1,868,808 (1.4) 6.98

2013 . . . . . . . . . . . 5,053 (6.6) 26,364 (1.5) 1,796,672 (3.9) 6.81

Annual Compound

Growth Rate 

(2004-2013) . . . . . (0.1) 0.8 5.2

(1) Includes firm off-system sales to other utilities.

 The following tables set forth sales and revenues by customer class for the years 2009 through 2013.

Sales (GWh) 

 Year 

 2009 2010 2011 2012 2013 

Class of % of % of % of % of % of

 Customers Total Total Total Total Total

Wholesale . . . . . . . . . 15,607 60.5 17,231 61.1 16,263 59.0 15,604 58.3 15,246 57.8

Large Industrial . . . . . 6,501 25.2 6,953 24.7 7,443 27.0 7,509 28.1 7,421 28.1

Residential,

 Commercial, Small

 Industrial and Other . 3,705 14.3 3,998 14.2 3,845 14.0 3,643 13.6 3,697 14.1

Total . . . . . . . . . . . . . . 25,813 100.0 28,182 100.0 27,551 100.0 26,756 100.0 26,364 100.0

Revenues (Dollars in Thousands)

 Year 

 2009 2010 2011 2012 2013 

Class of % of % of % of % of % of

 Customers Total Total Total Total Total

Wholesale . . . . . . . . . $ 1,028,193 61.1 $1,142,582 60.9 $1,129,445 59.6 $1,144,223 61.2 $1,058,943 58.9

Large Industrial ..... 346,318 20.6 376,247 20.1 415,309 21.9 389,742 20.9 381,689 21.2

Residential,

 Commercial, Small

 Industrial and Other . 308,958 18.3 356,435 19.0 350,093 18.5 334,843 17.9 356,040 19.9

Total . . . . . . . . . . . . . . $1,683,469 100.0 $1,875,264 100.0 $1,894,847 100.0 $1,868,808 100.0 $1,796,672 100.0

32
FINANCIAL INFORMATION

Historical Operating Results

A summary of the Authority's revenues available for debt service, lease payments and other purposes

for years 2009 through 2013 is set forth below:

Calendar Year

 (Dollars in Thousands) 

 2013 2012 2011 2010 2009 

Operating Revenues . . . . . . . . . . . . . . . . . . . $1,816,576 $1,887,797 $1,914,689 $1,894,902 $1,702,001

Other Income(1) . . . . . . . . . . . . . . . . . . . . . . 9,246 9,025 8,081 126 3,946

 Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,825,822 1,896,822 $1,922,770 $1,895,028 $1,705,947

Operating Expenses(2) . . . . . . . . . . . . . . . . . 1,327,370 1,379,158 1,366,423 1,318,814 1,201,140

Revenues Available for Debt Service, Lease

 Payments and Other Purposes . . . . . . . . . . 498,452 517,664 556,347 576,214 504,807

Debt Service on Revenue Bonds(3) ....... 0 0 0 0 3,298

Balance Available for Revenue Obligations, 

 Lease Payments and Other Purposes . . . . . 498,452 517,664 556,347 576,214 501,509

Debt Service on Revenue 

 Obligations(4) . . . . . . . . . . . . . . . . . . . . . . 325,420 356,852 342,621 362,506 339,875

Balance Available for Lease Payments and

 Other Purposes . . . . . . . . . . . . . . . . . . . . . . 173,032 160,812 213,726 213,708 161,634

Debt Service on Lease Payments . . . . . . . . . 939 1,346 1,559 1,936 2,664

Balance Available for Other Purposes . . . . . $ 172,093 $ 159,466 $ 212,167 $ 211,772 $ 158,970

Debt Service Coverage(5):

 Revenue Bonds, Revenue Obligations

 and Lease Payments . . . . . . . . . . . . . . . . 1.52 1.44 1.61 1.58 1.45

_________

(1) Includes interest subsidy payments for the 2010 Build America Bonds ("BABS"). Years 2009 through 2012 exclude gains on sale

of leased lots or rail cars.

(2) Year 2013 excludes depreciation only. Years 2009 through 2012 exclude depreciation and sums in lieu of taxes paid by Special

Reserve Fund.

(3) This category of bonds is no longer outstanding.

(4) The Revenue Obligation Resolution provides for debt service of Revenue Obligations to be paid from Revenues prior to payments 

for operating and maintenance expenses. See "SECURITY FOR THE 2014M1 BONDS - Rate Covenant."

(5) Calculation of coverage does not include debt service on Commercial Paper Notes and Other.

33
REGULATORY MATTERS

The Electric Utility Industry Generally

The electric utility industry in general has been affected by regulatory changes, market developments

and other factors which have impacted, and will probably continue to impact, the financial condition and

competitiveness of electric utilities and the level of utilization of facilities, such as those of the Authority. Such

factors include, among others, (a) effects of compliance with rapidly changing environmental, safety, licensing,

regulatory and legislative requirements, (b) changes resulting from conservation and demand-side management

programs on the timing and use of electric energy, (c) changes that might result from national energy policies,

(d) effects of competition from other electric utilities (including increased competition resulting from mergers,

acquisitions, and strategic alliances of competing electric (and gas) utilities and from competitors transmitting

less expensive electricity from much greater distances over an interconnected system) and new methods of

producing low cost electricity, (e) increased competition from independent power producers, marketers and

brokers, (f) self-generation by certain industrial, commercial and residential customers, (g) issues relating to

the ability to issue tax-exempt obligations, (h) restrictions on the ability to sell to nongovernmental entities

electricity from projects financed with outstanding tax-exempt obligations, (i) changes from projected future

load requirements, (j) increases in costs, and (k) shifts in the availability and relative costs of different fuels. 

Any of these factors (as well as other factors) could have an effect on the financial condition of any given

electric utility, including the Authority, and likely will affect individual utilities in different ways.

The Authority cannot determine with certainty what effects such factors will have on its business

operations and financial condition, but the effects could be significant. Extensive information on the electric

utility industry is available from sources in the public domain, and potential purchasers of the 2014M1 Bonds

should obtain and review such information.

Environmental Matters

Both the EPA and the DHEC have imposed various environmental regulations and permitting

requirements affecting the Authority’s facilities. These regulations and requirements relate primarily to

airborne pollution, the discharge of pollutants into waters and the disposal of solid and hazardous wastes. The

Authority endeavors to ensure its facilities comply with applicable environmental regulations and standards;

however, no assurance can be given that normal operations will not encounter occasional technical difficulties

or that necessary permits and authorizations will be received. Federal and state standards and procedures that

govern control of the environment and systems operations can change. These changes may arise from legislation,

regulatory action, and judicial interpretations regarding the standards, procedures and requirements for

compliance and issuance of permits. Therefore there is no assurance that units in operation, under construction,

or contemplated will remain subject to the regulations that are currently in effect. Furthermore, changes in the

clean air laws and environmental standards may result in increased capital and operating costs. 

Air Quality 

General Regulatory Requirements. The Authority is subject to a number of federal and state

laws and regulations which address air quality. Pursuant to the Clean Air Act (“CAA”), as amended,

the EPA promulgated primary and secondary national ambient air quality standards (“NAAQS”) with

respect to certain air pollutants, including particulate matter, SO2 and nitrogen oxide (“NOx”). These

standards are to be achieved by the application of control strategies developed by the states and

included in implementation plans which must be approved by the EPA to become effective. DHEC has

adopted a State Implementation Plan (“SIP”), which has been approved by the EPA, generally designed

to achieve the primary and secondary air quality standards. The EPA also promulgated the New Source

Performance Standards (“NSPS”) regulations establishing stringent emission standards for particulate

matter, SO2 and NOx emissions for fossil-fuel fired steam generators, and revised these standards in

1979 and 2005. Congress has enacted comprehensive amendments to the 1990 CAA, including the

addition of a new federal Acid Rain program to deal with acid precipitation.

Evolving Regulatory Requirements

Clean Air Interstate Rule and Cross State Air Pollution Rule. The federal Clean Air

Interstate Rule (the “CAIR”), which addresses NOx and SO2 emissions, took effect July 11,

2005. The EPA issued a final replacement to the CAIR rule, the Cross-State Air Pollution

Rule (“CSAPR”), on July 6, 2011, which was scheduled to take effect January 1, 2012. On

34
December 30, 2011 the U.S. Court of Appeals for the D.C. Circuit issued its ruling to stay the

CSAPR pending judicial review. On August 21, 2012, the U.S. Court of Appeals for the D.C.

Circuit issued its ruling vacating CSAPR. The EPA appealed the Court’s ruling but the appeal

was denied by the U.S. Court of Appeals for the D.C. Circuit. On June 24, 2013 the U.S.

Supreme Court granted EPA's request for the Supreme Court to review the CSAPR decision.

CAIR was remanded to the EPA by the court but still remains in effect until a replacement

rule is finalized. The Authority is in compliance with CAIR and expects its existing units

could comply with a replacement rule similar to CAIR or CSAPR without any significant

capital improvements.

Mercury and Air Toxics Standard. Over the last several years EPA has been

evaluating appropriate Maximum Achievable Control Technology (“MACT”) standards for

source categories and proposing various regulatory programs for mercury control for power

plants. On April 16, 2012, the final rule, renamed the Mercury and Air Toxics Standard

(“MATS”), became effective. Although somewhat less stringent than the earlier proposed

MACT rule, MATS will have significant impacts on the Authority’s coal-fired units. The

Authority is still evaluating the impact of this rule, with a compliance deadline of April 16,

2015 and has preliminarily estimated the capital cost not to exceed $100 million.

Greenhouse Gases. In March, 2012, the EPA proposed NSPS for emissions of

carbon dioxide (“CO2”) for new affected fossil fuel-fired electric utility generating units

(“EGUs”). The EPA proposed these requirements because CO2 is a greenhouse gas (“GHG”)

and fossil fuel-fired power plants are the country’s largest anthropogenic stationary source

emitters of GHGs. The EPA in 2009 found that by causing or contributing to climate change,

GHGs endanger both the public health and the public welfare of current and future

generations. The proposed requirements, which are strictly limited to new sources, would

require new fossil fuel-fired EGUs greater than 25 megawatt electric to meet an output-based

standard of 1,000 pounds of CO2 per megawatt-hour, based on the performance of widely used

natural gas combined cycle technology. This limit essentially precludes the construction of

new coal fired generation without CO2 controls, such as carbon capture and sequestration. 

On September 22, 2009, the EPA announced a final rule on the new GHG reporting

program. This rule is commonly referred to as the Greenhouse Gas Mandatory Reporting

Rule (“GHG-MRR”). Beginning January 1, 2010, the Authority was required to annually

report GHG emissions data to the EPA for any of its facilities that emit 25,000 metric tons or

more of CO2 or equivalent per year. This reporting requirement applies to the Authority’s

larger generating facilities, and electrical transmission and distribution equipment. The

Authority has filed annual reports in compliance with this requirement.

The EPA and Congress continue to consider strong measures that will reduce GHG

emissions from major sources, including electric utilities, as well as implementation of other

complementary measures to reduce GHG emissions. In a June 25, 2013 memorandum,

President Obama directed the EPA to repropose its NSPS for GHGs for new power plants by

September 20, 2013 and to propose standards, regulations, or guidelines, as appropriate, by

June 1, 2014, for existing, reconstructed or modified plants. The memo directed the EPA to

issue final rules or guidelines for existing plants by June 1, 2015. On January 8, 2014 the

EPA published in the Federal Register the proposed CO2 NSPS for GHGs for new power

plants, with comments due May 9, 2014. The Authority plans to submit comments as it relates

to potential new generation for the Authority's fleet. The potential cost impact of future GHG

regulation or legislation could be significant and the Authority will continue to monitor the

status.

Water Quality

General Regulatory Requirements. The Authority is subject to a number of federal and state

laws and regulations which address water quality. The Clean Water Act (“CWA”) prohibits the

discharge of pollutants, including heat, from point sources into waters of the United States, except as

authorized in the National Pollutant Discharge Elimination System (“NPDES”) permit program. The

DHEC has been delegated NPDES permitting authority by the EPA and administers the program for

the State. Industrial wastewater discharges from all stations and the regional water plants are governed

by NPDES permits. The DHEC also has permitting authority for stormwater discharges and the

35
Authority manages stormwater pursuant to the DHEC issued Industrial General Permits and

Construction General Permits.

Evolving Regulatory Requirements

316(b) Fish Protection Regulations. Section 316(b) of the CWA requires that

NPDES permits for facilities with cooling water intake structures ensure that the structures

reflect the best technology available to minimize adverse environmental impacts from

impingement and entrainment of fish and egg larvae. The EPA published a draft rule in the

Federal Register on April 20, 2011. Compliance dates range from six months to eight years

for various components of the rule and are geared to the time the EPA issues the final rule. 

The final rule is anticipated April 2014. The Authority has reviewed the draft rule to

determine the potential impact to the Authority’s applicable generating facilities, which are

Jefferies (Units 1 & 2), Cross, Winyah, and Rainey. The Authority has estimated and budgeted

for an estimated cost of compliance based on the draft rule.

Effluent Limitation Guidelines. On April 19, 2013, the EPA released a proposed

rulemaking pursuant to section 304(b) of the CWA establishing effluent limitation guidelines

(“ELGs”) for all steam electric generating units. The final rule is anticipated in late 2014. 

Implementation of the rule will require generating units to comply with specific effluent

limitations, based upon the availability and cost of applicable pollution control technology. 

The guidelines propose stricter performance standards that will require upgrades and

installation of additional wastewater treatment systems for certain facilities including Winyah

and Cross Generating Stations. EPA sets the ELG limits based on their evaluation of the “best

available” treatment technologies that the EPA believes are economically achievable. The

Authority is evaluating the proposed rule and has provided comments. The Authority cannot

fully estimate the potential cost of compliance with the proposed rule.

Solid and Hazardous Waste and Hazardous Substances

General Regulatory Requirements. The Authority is subject to a number of federal and state

laws and regulations which address hazardous substances and wastes. These include the CWA, which

imposes substantial penalties for spills of oil or Federal EPA-listed hazardous substances into water

and for failure to report such spills; the Comprehensive Environmental Response, Compensation, and

Liability Act of 1980 (“CERCLA”) which provides for the reporting requirements to cover the release

of hazardous substances generally into the environment, including water, land and air, and imposes

liability upon any generators, transporters or arrangers of disposal of hazardous substances, and the

CERCLA and Superfund Amendments and Reauthorization Act (“SARA”), which require compliance

with programs for emergency planning and public information. Additionally, the EPA regulations

under the Toxic Substances Control Act impose stringent requirements for labeling, handling, storing

and disposing of polychlorinated biphenyls (“PCB”) and associated equipment. There are regulations

covering PCB notification and manifesting, restrictions on disposal of drained electrical equipment,

spill cleanup record-keeping requirements, etc. The Authority has a comprehensive PCB management

program in response to these regulations.

Evolving Regulatory Requirements

Solid Waste – Coal Combustion Residual Rule. In addition to handling hazardous

substances, the Authority generates solid waste associated with the combustion of coal, the

vast majority of which is fly ash, bottom ash, scrubber sludge and gypsum. These wastes,

known as Coal Combustion Residuals (“CCRs”), are exempt from hazardous waste regulation

under the Resource Conservation and Recovery Act (“RCRA”). However, in 2010, the EPA

issued a proposed rule to regulate CCRs under RCRA. The proposed rule provides two

options for regulation of the CCRs. One option is to regulate the CCRs as a RCRA Subtitle

C, hazardous waste, and the other is to regulate the CCRs as a RCRA Subtitle D, nonhazardous waste. The proposed rule could impact beneficial reuse of CCRs as a nonhazardous waste byproduct and could impact the Authority’s method of management of CCRs

with regard to the coal fired units in operation at Cross and Winyah and the recently retired

coal fired units at Grainger and Jefferies. No firm estimates relative to the cost of

implementing this draft regulation, when promulgated, can be made at this time since the final

outcome of the rule is uncertain. A consent decree filed in US District Court for the District

36
of Columbia on January 29, 2014 requires EPA to publish notice of a final action by

December 19, 2014.

Industrial Solid Waste Landfills. At Cross Generating Station, dry disposal of CCRs

into an industrial Class 2 solid waste landfill is governed by a Consent Agreement executed

on April 29, 2011 between the Authority and DHEC, which provides for operation of the

landfill until December 31, 2015. The Authority has received all necessary permits to

construct a Class 3 solid waste landfill at Cross Generating Station. The Authority expects

to complete construction and place the landfill into operation prior to December 31, 2015. 

The Authority will dispose of CCRs into the Class 3 solid waste landfill after that date. 

Drinking Water

The Authority continues to monitor for Safe Drinking Water Act regulatory issues impacting

drinking water systems at the Authority’s Regional Water Systems, generating stations, substations and

other auxiliary facilities. DHEC has regulatory authority of potable water systems in the State. The

State Primary Drinking Water Regulation, R.61-58, governs the design, construction and operational

management of all potable water systems in the State subject to and consistent with the requirements

of the Safe Drinking Water Act and the implementation of federal drinking water regulations. 

FERC Hydro Licensing

The Authority operates its Jefferies Hydro Station and certain other property, including the Pinopolis

Dam on the Cooper River and the Santee Dam on the Santee River, which are major parts of the Authority’s

integrated hydroelectric complex, under a license issued by the FERC pursuant to the Federal Power Act

(“FPA”). The project is currently undergoing relicensing and a Notice of Intent (“NOI”) to relicense was filed

with the FERC on November 13, 2000. The final license application was submitted March 12, 2004. Due to

a number of Additional Information Requests, the relicensing process has extended beyond the license expiration

date. The FERC has issued a standing annual license renewal until a final license is issued. 

 The FERC issued its Final Environmental Impact Statement (“EIS”) in October, 2007. The South

Carolina Department of Natural Resources, the U.S. Fish and Wildlife Service, and the Authority have jointly

signed and filed a settlement agreement with the FERC that among other things, identifies fish passage and

outflow guidelines during the term of the next license. The National Marine Fisheries Service ("NMFS") chose

not to join in the settlement agreement and has submitted mandatory fishway conditions under §18 of the FPA

and flow recommendations under §10 of that Act that are inconsistent with the settlement agreement. 

In November 2007, FERC requested that NMFS undertake an Endangered Species Act ("ESA") Section

7 consultation with regard to the relicensing project. In July of 2010, as a function of the required Section 7

consultation, NMFS submitted a draft biological opinion containing recommendations for the endangered

shortnose sturgeon. The recommendations, if adopted, would result in substantial additional costs for operating

the project. The Authority provided a response to those recommendations in September 2010. The Authority

cannot predict when NMFS will issue a final biological opinion or the final outcome of the FERC relicensing

process. 

NERC Regulation

The NERC establishes and enforces reliability standards, including critical infrastructure protection

standards, for the bulk power system. The critical infrastructure protection standards focus on controlling access

to critical physical and cyber security assets. Compliance with these standards is mandatory. The maximum

penalty that may be levied for violating a NERC reliability standard is $1 million per violation, per day. The

Authority has self-reported some violations of NERC reliability or critical infrastructure protections standards

and paid the necessary fines. The Authority has formal programs, processes, and policies in place to promote

compliance with these standards. However, it is not possible to predict whether the Authority will have future

violations or what the fines for such violations might be.

37
Nuclear Matters

Summer Nuclear Unit 1 is subject to regulation by the NRC. SCE&G and the Authority were required

to obtain liability insurance and a United States Government indemnity agreement for Summer Nuclear Unit 1

in order for the NRC operating license to be issued. This primary insurance and the retrospective assessment

are to insure against the maximum liability under the federal Price-Anderson Act for any public claims arising

from a nuclear incident. The Energy Policy Act of 2005 extends the Price-Anderson Act until 2025.

The NRC requires that a licensee of a nuclear reactor provide minimum financial assurance of its ability

to decommission its nuclear facilities. In compliance with the applicable NRC regulations, the Authority

established an external trust to comply with the new regulations. The Authority began making deposits into the

external decommissioning fund in September 1990.

In addition to providing for the minimum requirements imposed by the NRC, the Authority established

in 1983 an internal decommissioning fund. Based on the most recent decommissioning cost estimates developed

by SCE&G, both the internal and external funds, which had a combined market value of approximately $185

million at December 31, 2013, along with future deposits into the external trust and investment earnings, are

estimated to provide sufficient funds for the Authority's one-third share of the total estimated decommissioning

costs.

Potential Nuclear Plant Guidelines. In March 2011, a major earthquake and tsunami struck Japan and

caused substantial damage to the nuclear generating units at the Fukushima Daiichi generating plant. The events

in Japan have created uncertainties that may affect future costs for operating nuclear plants. Specifically, the

NRC is performing additional operational and safety reviews of nuclear facilities in the U.S., which could

potentially impact future operations and capital requirements. On March 12, 2012, the NRC issued three orders

and a request for information based on the July 2011 NRC task force report recommendations that included,

among other items, additional mitigation strategies for beyond-design-basis events, enhanced spent fuel pool

instrumentation capabilities, hardened vents for certain classes of containment structures, site specific evaluations

for seismic and flooding hazards, and various plant evaluations to ensure adequate coping capabilities during

station blackout and other conditions. On August 29, 2012, the NRC staff issued the final interim staff guidance

document, which offers acceptable approaches to meeting the requirements of the NRC's orders before the

December 31, 2016 compliance deadline. The interim staff guidance is not mandatory, but licensees would be

required to obtain NRC approval for taking an approach other than as outlined in the interim staff guidance. The

final form and the resulting impact of any changes to safety requirements for nuclear reactors will be dependent

on further review and action by the NRC and cannot be determined at this time; however, management does not

currently anticipate that the associated compliance costs would have a material impact on the Authority's

financial statements.

LITIGATION

Except as noted below, there are no actions, suits, or governmental proceedings pending or, to the

knowledge of the Authority, threatened before any court, administrative agency, arbitrator or governmental body

which would, if determined adversely to the Authority, have a material adverse effect on its financial condition.

However, even if determined adversely to the Authority, no such actions, suits, or governmental proceedings

would have a material adverse effect on the Authority’s ability to transact its business or meet its obligations

under the Revenue Obligation Resolution.

Santee River Corps Claim. As of March 2010, the Authority had paid approximately $221 million,

including interest, in settlement of a lawsuit brought by a number of landowners located along the Santee River

primarily in Williamsburg and Georgetown Counties, South Carolina. The plaintiffs claimed damage to their

real estate as a result of flooding that has occurred since the Corps’ Cooper River Rediversion Project was

completed in 1985. The Authority also paid an additional $10.4 million in costs and attorneys’ fees to the

plaintiffs in August, 2011. The Authority pursued an indemnification claim against the Corps before the Armed

Services Board of Contract Appeals (“ASBCA”). 

On February 14, 2013, ASBCA ruled that the Authority is entitled to reimbursement from the Corps

in the amount of $234,865,797.11 for costs incurred as a result of the Santee River litigation. The award by the

ASBCA also includes interest on the indemnification amount pursuant to the Contract Disputes Act, calculated

from August 20, 2001, until paid. On June 11, 2013 the Corps appealed the ASBCA decision to the United States

Court of Appeals for the Federal Circuit. The Authority cannot predict the outcome of the appeal.

38
Grainger Ash Pond Litigation. In June 2012, several environmental advocacy groups filed suit against

the Authority in the Court of Common Pleas in Horry County seeking injunctive relief with regard to closure of

ash ponds at the Grainger Generating Station. The suit did not seek damages but alleged that an unlawful

discharge of arsenic and other contaminants had occurred and requested that the court order the removal and

offsite storage of all ash contained in the ponds. In April 2013, an environmental advocacy group filed suit

against the Authority alleging that violations of the federal CWA had occurred at Grainger Generating Station. 

The suit did not seek damages but made claims for injunctive relief, civil penalties and costs and attorney's fees. 

The Authority settled both suits in November 2013. The settlement did not require the Authority to make any

payments to the litigants. The Authority intends to properly close the ash ponds by excavation and beneficial

use of the ash in accordance with regulatory requirements. 

Horry Electric Cooperative, Inc. ("Horry Co-op") Suit. In May 2013, Horry Co-op, a member of

Central, sued the Authority seeking indemnification for claims in a class action lawsuit brought against Horry

Co-op by certain of its customers. The customers allege mold damage to their homes was caused by vapor

barriers installed in accordance with the Authority's energy efficiency recommendations. Horry Co-op's

complaint alleges the Authority knew the vapor barrier could cause moisture problems but failed to disclose the

information to Horry Co-op and failed to advise Horry Co-op that the vapor barrier should be a recommendation

rather than a requirement. The Authority has been informed that a settlement, subject to court approval, has been

reached in the underlying class action lawsuit against Horry Co-op. The settlement provides for the

establishment of two funds, totaling $6 million dollars, to pay the claims of the class members. The Authority

has filed a motion to dismiss the claims brought against it by Horry Co-op. The Authority intends to vigorously

defend the lawsuit but cannot predict the outcome.

FINANCIAL ADVISOR

The Authority has retained Public Financial Management, Inc., as Financial Advisor in connection with

the issuance of the 2014M1 Bonds.

TAX MATTERS

The 2014M1 Bonds

Federal Income Tax Generally. On the date of issuance of the 2014M1 Bonds, Haynsworth Sinkler

Boyd, P.A., Charleston, South Carolina (“Bond Counsel”), will render an opinion that, assuming continuing

compliance by the Authority with the requirements of the Internal Revenue Code of 1986, as amended (the

“Code”), and the applicable regulations promulgated thereunder (the “Regulations”) and further subject to certain

considerations described in “Collateral Federal Tax Considerations” below, under existing statutes, regulations

and judicial decisions, interest on the 2014M1 Bonds is excludable from the gross income of the registered

owners thereof for federal income tax purposes. Interest on the 2014M1 Bonds will not be treated as an item

of tax preference in calculating the alternative minimum taxable income of individuals or corporations; however,

interest on the 2014M1 Bonds will be included in the calculation of adjusted current earnings in determining the

alternative minimum tax liability of corporations. The Code contains other provisions that could result in tax

consequences, upon which no opinion will be rendered by Bond Counsel, as a result of (i) ownership of the

2014M1 Bonds or (ii) the inclusion in certain computations of interest that is excluded from gross income. 

The opinion of Bond Counsel will be limited to matters relating to the authorization and validity of the

2014M1 Bonds and the tax-exempt status of interest on the 2014M1 Bonds as described herein. Bond Counsel

makes no statement regarding the accuracy and completeness of this Official Statement.

 

The opinion of Bond Counsel is based on current legal authority, covers certain matters not directly

addressed by such authorities, and represents Bond Counsel's judgment as to the proper treatment of the 2014M1

Bonds for federal income tax purposes. Bond Counsel's opinions are based upon existing law, which is subject

to change. Such opinions are further based on factual representations made to Bond Counsel as of the date

thereof. Bond Counsel assumes no duty to update or supplement its opinions to reflect any facts or circumstances

that may thereafter come to Bond Counsel's attention or to reflect any changes in law that may thereafter occur

or become effective. Moreover, Bond Counsel's opinions are not a guarantee of a particular result, and are not

binding on the IRS or the courts; rather, such opinions represent Bond Counsel's professional judgment based

on its review of existing law, and in reliance on the representations and covenants that it deems relevant to such

opinions.

39
The opinion of Bond Counsel described above is subject to the condition that the Authority comply with

all requirements of the Code and the Regulations, including, without limitation, certain limitations on the use,

expenditure and investment of the proceeds of the 2014M1 Bonds and the obligation to rebate certain earnings

on investments of proceeds to the United States Government, that must be satisfied subsequent to the issuance

of the 2014M1 Bonds in order that interest thereon be, or continue to be, excludable from gross income for

federal income tax purposes. The Authority has covenanted to comply with each such requirement. Failure to

comply with certain of such requirements may cause the inclusion of interest on the 2014M1 Bonds in gross

income for federal income tax purposes retroactive to the date of issuance of the 2014M1 Bonds. The opinion

of Bond Counsel delivered on the date of issuance of the 2014M1 Bonds is conditioned on compliance by the

Authority with such requirements, and Bond Counsel has not been retained to monitor compliance with the

requirements subsequent to the issuance of such 2014M1 Bonds.

Collateral Federal Tax Considerations. Prospective purchasers of the 2014M1 Bonds should be aware

that ownership of tax-exempt obligations may result in collateral federal income tax consequences to certain

taxpayers, including, without limitation, financial institutions, property and casualty insurance companies, life

insurance companies, certain foreign corporations, certain S corporations, individual recipients of Social Security

or Railroad Retirement benefits and taxpayers who may be deemed to have incurred or continued indebtedness

to purchase or carry tax-exempt obligations. The 2014M1 Bonds are not "qualified tax-exempt obligations"

under Section 265(b)(3) of the Code. Bond Counsel expresses no opinion concerning such collateral income tax

consequences, and prospective purchasers of 2014M1 Bonds should consult their tax advisors as to the

applicability thereof.

Future legislation, if enacted into law, or clarification of the Code may cause interest on the 2014M1

Bonds to be subject, directly or indirectly, to federal income taxation, or otherwise prevent owners from realizing

the full current benefit of the tax status of such interest. The introduction or enactment of any such future

legislation or clarification of the Code may also affect the market price for, or marketability of, the 2014M1

Bonds. No prediction can be made concerning future legislation which if passed might adversely affect the tax

treatment of interest on the 2014M1 Bonds. Prospective purchasers of the 2014M1 Bonds should consult their

own tax advisors regarding any pending or proposed federal tax legislation, as to which Bond Counsel expresses

no opinion.

The IRS has established an ongoing program to audit tax-exempt obligations to determine whether

interest on such obligations is includable in gross income for federal income tax purposes. Bond Counsel cannot

predict whether the IRS will commence an audit of the 2014M1 Bonds. Bond Counsel’s engagement with

respect to the 2014M1 Bonds ends with the issuance of the 2014M1 Bonds and unless separately engaged, Bond

Counsel is not obligated to defend the Authority or the owners of 2014M1 Bonds regarding the tax-exempt

status of the 2014M1 Bonds in the event of an audit examination by the IRS. The IRS has taken the position that,

under the standards of practice before the IRS, Bond Counsel must obtain a waiver of a conflict of interest to

represent an issuer in an examination of tax exempt bonds for which Bond Counsel had issued an approving

opinion. Under current procedures, parties other than the Authority and their appointed counsel, including the

owners of 2014M1 Bonds, would have little, if any, right to participate in the audit examination process.

Moreover, because achieving judicial review in connection with an audit examination of tax-exempt bonds is

difficult, obtaining an independent review of IRS positions with which the Authority legitimately disagrees, may

not be practicable. Any action of the IRS, including but not limited to selection of the 2014M1 Bonds for audit,

or the course or result of such audit, or an audit of bonds presenting similar tax issues may affect the market price

for, or the marketability of, the 2014M1 Bonds, and may cause the Authority or the owners of 2014M1 Bonds

to incur significant expense, regardless of the ultimate outcome. 

40
State Tax Exemption

Bond Counsel is of the further opinion that the 2014M1 Bonds and the interest thereon are exempt from

all taxation by the State of South Carolina, its counties, municipalities and school districts except estate, transfer

or certain franchise taxes. Interest paid on the 2014M1 Bonds is currently subject to the tax imposed on banks

by Section 12-11-20, Code of Laws of South Carolina 1976, as amended, which is enforced by the South

Carolina Department of Revenue and Taxation as a franchise tax. The opinion of Bond Counsel is limited to the

laws of the State of South Carolina and federal tax laws. No opinion is rendered by Bond Counsel concerning

the taxation of the 2014M1 Bonds or the interest thereon under the laws of any other jurisdiction. 

APPROVAL OF LEGAL PROCEEDINGS

Haynsworth Sinkler Boyd, P.A., Charleston, South Carolina, Bond Counsel to the Authority, will render

an opinion with respect to the validity and tax treatment of the 2014M1 Bonds. Such opinion will be attached

to the 2014M1 Bonds and will be in substantially the form set forth in Appendix III. Certain legal matters will

be passed upon on behalf of the Authority by James E. Brogdon, Jr., its Executive Vice President and General

Counsel.

MISCELLANEOUS

The agreements of the Authority with the owners of the 2014M1 Bonds are fully set forth in the

Revenue Obligation Resolution. This Official Statement is not to be construed as a contract with the purchasers

of the 2014M1 Bonds. Any statements herein involving matters of opinion or estimates, whether or not expressly

so stated, are intended merely as such and not as representations of fact. This Official Statement has been

approved by the Board of Directors of the Authority. 

South Carolina Public Service Authority 

Lonnie N. Carter 

President and Chief Executive Officer

41
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Appendix I

I-1

Combined Statements of Net Position

South Carolina Public Service Authority

As of December 31, 2013 and 2012

2013 2012

(Thousands)

ASSETS

Current assets

 Unrestricted cash and cash equivalents $ 172,738 $ 203,591 

 Unrestricted investments 526,584 335,053 

 Restricted cash and cash equivalents 182,455 273,542 

 Restricted investments 762,650 342,191 

 Receivables, net of allowance for doubtful accounts of $1,315

 and $1,333 at December 31, 2013 and 2012, respectively 189,092 205,034 

 Materials inventory 113,865 106,333 

 Fuel inventory

 Fossil fuels 446,998 483,407 

 Nuclear fuel-net 163,147 84,470 

 Interest receivable 2,664 1,731 

 Prepaid expenses and other current assets 248,520 252,886 

 Total current assets 2,808,713 2,288,238 

Noncurrent assets

 Restricted cash and cash equivalents 1,535 1,911 

 Restricted investments 109,060 112,535 

 Capital assets

 Utility plant 6,910,962 6,744,928 

 Long lived assets-asset retirement cost 507,394 507,394 

 Accumulated depreciation (3,150,020) (2,954,471)

 Total utility plant-net 4,268,336 4,297,851 

 Construction work in progress 2,100,631 1,643,507 

 Other physical property-net 6,084 6,560 

 Investment in associated companies 6,840 8,124 

 Unamortized debt expenses 36,473 32,951 

 Costs to be recovered from future revenue 227,561 220,165 

 Regulatory asset-asset retirement obligation 603,663 544,583 

 Other noncurrent and regulatory assets 399,465 433,144 

 Total noncurrent assets 7,759,648 7,301,331 

Total assets $ 10,568,361 $ 9,589,569 

DEFERRED OUTFLOWS OF RESOURCES

 Accumulated decrease in fair value of hedging derivatives $ 19,367 $ 34,891 

 Unamortized loss on refunded and defeased debt 119,868 138,072 

Total deferred outflows of resources $ 139,235 $ 172,963 

Total assets & deferred outflows of resources $ 10,707,596 $ 9,762,532 

The accompanying notes are an integral part of these combined financial statements.
I-2

Combined Statements of Net Position (continued)

South Carolina Public Service Authority

As of December 31, 2013 and 2012

2013 2012

(Thousands)

LIABILITIES

Current liabilities

 Current portion of long-term debt $ 133,671 $ 334,842 

 Accrued interest on long-term debt 100,159 108,465 

 Commercial paper 372,073 329,283 

 Accounts payable 216,163 228,958 

 Other current liabilities 69,978 70,513 

 Total current liabilities 892,044 1,072,061 

Noncurrent liabilities

 Construction liabilities 3,616 2,428 

 Asset retirement obligation liability 1,024,253 1,002,313 

 Total long-term debt (net of current portion) 6,313,821 5,222,951 

 Unamortized debt discounts and premiums 142,558 190,368 

 Long-term debt-net 6,456,379 5,413,319 

Other credits and noncurrent liabilities 97,182 98,153 

 Total noncurrent liabilities 7,581,430 6,516,213 

Total liabilities $ 8,473,474 $ 7,588,274 

DEFERRED INFLOWS OF RESOURCES

 Accumulated increase in fair value of hedging derivatives $ 8,146 $ 3,423 

 Nuclear decommissioning costs 185,849 196,252 

Total deferred inflows of resources $ 193,995 $ 199,675 

NET POSITION

 Net invested in capital assets $ 893,339 $ 894,920

 Restricted for debt service 92,662 140,038 

 Unrestricted 1,054,126 939,625

Total net position $ 2,040,127 $ 1,974,583 

Total liabilities, deferred inflows of resources & net position $ 10,707,596 $ 9,762,532 
I-3

Combined Statements of Revenues, Expenses and Changes in Net Position

South Carolina Public Service Authority

Years Ended December 31, 2013 and 2012

2013 2012

(Thousands)

Operating revenues

 Sale of electricity $ 1,796,230 $ 1,868,365 

 Sale of water 7,282 6,594 

 Other operating revenue 13,064 12,838 

 Total operating revenues 1,816,576 1,887,797 

Operating expenses

 Electric operating expenses

 Production 104,740 103,655 

 Fuel 741,255 829,085 

 Purchased and interchanged power 217,311 161,349 

 Transmission 24,555 24,080 

 Distribution 10,727 10,625 

 Customer accounts 15,656 15,660 

 Sales 6,016 5,803 

 Administrative and general 91,792 90,501 

 Electric maintenance expense 106,463 135,201 

 Water operation expense 2,502 2,217 

 Water maintenance expense 890 713 

 Total operation and maintenance expenses 1,321,907 1,378,889 

 Depreciation 196,812 187,382 

 Sums in lieu of taxes 5,463 5,209 

 Total operating expenses 1,524,182 1,571,480 

 Operating income 292,394 316,317 

Nonoperating revenues (expenses)

 Interest and investment revenue 3,945 4,892 

 Net decrease in the fair value of investments (2,320) (2,966)

Interest expense on long-term debt (221,067) (215,414)

 Interest expense on commercial paper and other (4,063) (3,135)

 Amortization expense 4,352 (11,784)

 Costs to be recovered from future revenue 7,396 9,155 

 U.S. Treasury subsidy on Build America Bonds 7,486 8,132 

 Other-net (2,185) (720)

 Total nonoperating revenues (expenses) (206,456) (211,840)

 Income before transfers 85,938 104,477 

Capital contributions & transfers

 Distribution to the State (20,394) (19,617)

 Reduction in water system equity 0 (8)

 Total capital contributions & transfers (20,394) (19,625)

 Change in net position 65,544 84,852 

Total net position-beginning 1,974,583 1,889,731 

Total net position-ending $ 2,040,127 $ 1,974,583 

The accompanying notes are an integral part of these combined financial statements.
I-4

Combined Statements of Cash Flows

South Carolina Public Service Authority

Years Ended December 31, 2013 and 2012

2013 2012

(Thousands)

Cash flows from operating activities

 Receipts from customers $ 1,832,536 $ 1,891,420 

 Payments to non-fuel suppliers (262,973) (516,867)

 Payments for fuel (736,022) (821,705)

 Purchased power (217,386) (158,122)

 Payments to employees (158,002) (159,670)

 Other receipts-net 272,613 213,252

 Net cash provided by operating activities 730,766 448,308

Cash flows from non-capital related financing activities

 Distribution to the State (20,394) (19,617)

 Reduction in water system equity 0 (8)

 Net cash used in non-capital related financing activities (20,394) (19,625)

Cash flows from capital-related financing activities

 Proceeds from sale of bonds 1,866,374 865,190 

 Proceeds from issuance of commercial paper notes 284,897 144,331 

 Repayment of commercial paper notes (242,107) (121,614)

 Refunding / defeasance of long-term debt (856,621) (319,225)

 Repayment of long-term debt (167,412) (151,210)

 Interest paid on long-term debt (279,148) (265,682)

 Interest paid on commercial paper and other (5,983) (5,000)

 Construction and betterments of utility plant (730,119) (488,236)

 Bond issuance and other related costs (34,217) 50,120 

 Other - net (60,487) (23,048)

 Net cash used in capital-related financing activities (224,823) (314,374)

Cash flows from investing activities

 Net (decrease)/increase in investments (610,834) 35,440 

 Interest on investments 2,969 5,311 

 Net cash (used in)/provided by investing activities (607,865) 40,751 

 Net (decrease)/increase in cash and cash equivalents (122,316) 155,060 

 Cash and cash equivalents-beginning 479,044 323,984 

 Cash and cash equivalents-ending $ 356,728 $ 479,044 

The accompanying notes are an integral part of these combined financial statements.
I-5

Combined Statements of Cash Flows (continued)

South Carolina Public Service Authority

Years Ended December 31, 2013 and 2012

2013 2012

(Thousands)

Reconciliation of operating income to net cash provided by 

operating activities

 Operating income $ 292,394 $ 316,317 

 Adjustments to reconcile operating income to net cash provided by 

operating activities

 Depreciation 196,812 187,382

 Amortization of nuclear fuel 28,500 21,813 

 Net power gains involving associated companies (25,243) (44,686)

 Distributions from associated companies 22,444 42,117 

 Advances to associated companies (4) (6)

 Other income and expense 12,895 14,653

 Changes in assets and liabilities

 Accounts receivable-net 15,942 3,576 

 Inventories 28,877 7,223 

 Prepaid expenses 23,491 3,844 

 Other deferred debits 73,245 1,550 

 Accounts payable 58,992 (71,911)

 Other current liabilities 319 (17,011)

 Other noncurrent liabilities 2,102 (16,553)

 Net cash provided by operating activities $ 730,766 $ 448,308

Composition of cash and cash equivalents

Current

 Unrestricted cash and cash equivalents $ 172,738 $ 203,591

 Restricted cash and cash equivalents 182,455 273,542

Noncurrent

 Restricted cash and cash equivalents 1,535 1,911

 Cash and cash equivalents at the end of the year $ 356,728 $ 479,044 
I-6

NOTES

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: 

A - Reporting Entity - The South Carolina Public Service Authority (the Authority or Santee Cooper), a 

component unit of the State of South Carolina, was created in 1934 by the State legislature. The Santee Cooper 

Board of Directors (Board) is appointed by the Governor of South Carolina with the advice and consent of the 

Senate. The purpose of the Authority is to provide electric power and wholesale water to the people of South 

Carolina. Capital projects are funded by bonds, commercial paper and internally generated funds. As authorized 

by State law, the Board sets rates charged to customers to pay debt service and operating expenses and to 

provide funds required under bond covenants.

B - System of Accounts - The accounting records of the Authority are maintained on an accrual basis in 

accordance with accounting principles generally accepted in the United States (GAAP) issued by the 

Governmental Accounting Standards Board (GASB) applicable to governmental entities that use proprietary fund 

accounting and the Financial Accounting Standards Board (FASB) that do not conflict with rules issued by the 

GASB. 

The Authority’s combined financial statements include the accounts of the Lake Moultrie and Lake Marion 

Regional Water Systems after elimination of inter-company accounts and transactions. The accounts are 

maintained substantially in accordance with the Uniform System of Accounts prescribed by the Federal Energy 

Regulatory Commission (FERC) for the electric system and the National Association of Regulatory Utility 

Commissioners (NARUC) for the water systems. 

The Authority also complies with policies and practices prescribed by its Board and practices common in both 

industries. As the Board is authorized to set rates, the Authority follows GASB 62. This standard provides for the 

reporting of assets and liabilities consistent with the economic effect of the rate structure. 

The preparation of financial statements in conformity with GAAP requires management to make estimates and

assumptions in the Authority’s reporting. This practice affects the reported amounts of assets and liabilities and 

disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of 

revenues and expenses during the reporting period. Actual results may differ from those estimates.

C - Current and Noncurrent - The Authority presents assets and liabilities in order of relative liquidity. The 

liquidity of an asset is determined by how readily it is expected to be converted to cash and whether restrictions 

limit the use of the resources. The liquidity of a liability is based on its maturity, or when cash is expected to be 

used to liquidate the liability.

D - Restricted Assets - For purposes of the Combined Statements of Net Position and Combined Statements 

of Cash Flows, assets are restricted when constraints are placed on their use by either:

(1) External creditors, grantors, contributors, or laws or regulations of other governments; or

(2) Law through constitutional provisions or enabling legislation.

Assets not meeting the requirements of restricted are classified as unrestricted.

E - Cash and Cash Equivalents - For purposes of the Combined Statements of Net Position and Combined 

Statements of Cash Flows, the Authority considers highly liquid investments with original maturities of ninety days 

or less and cash on deposit with financial institutions as Unrestricted and Restricted cash and cash equivalents. 

F - Inventory - Material and fuel inventories are carried at weighted average costs. At the time of issuance or 

consumption, an expense is recorded at the weighted average cost. 
I-7

G - Utility Plant - Utility plant is recorded at cost, which includes materials, labor, overhead and interest 

capitalized during construction. Interest is capitalized only when interest payments are funded through 

borrowings. The Authority capitalized $83.7 million of interest in 2013. Other interest expense is recovered 

currently through rates. The costs of maintenance, repairs and minor replacements are charged to appropriate 

operation and maintenance expense accounts. The costs of renewals and betterments are capitalized. The 

original cost of utility plant retired and the cost of removal, less salvage, are charged to accumulated depreciation.

H - Depreciation - Depreciation is computed using composite rates on a straight-line basis over the estimated 

useful lives of the various classes of the plant. Composite rates are applied to the gross plant balance of various 

classes of assets which includes appropriate adjustments for cost of removal and salvage. The Authority 

periodically has depreciation studies performed by independent parties to assist management in establishing 

appropriate composite depreciation rates. 

Annual depreciation provisions, expressed as a percentage of average depreciable utility plant in service, were as 

follows:

Years Ended December 31, 2013 2012

Annual Average Depreciation Percentages 2.9% 2.8%

Note: Depreciation expense includes amortization of property under capitalized leases.

I - Retirement of Long Lived Assets - The Authority follows the guidance of FASB ASC 410 in regards to the 

decommissioning of V.C. Summer Nuclear Station and closing coal-fired generation ash ponds. The 

requirements for both were recorded within Capital assets on the accompanying Combined Statements of Net 

Position.

The asset retirement obligation (ARO) is adjusted each period for any liabilities incurred or settled during the 

period, accretion expense and any revisions made to the estimated cash flows. The following table summarizes 

the Authority’s transactions:

Years Ended December 31, 2013 2012

Nuclear Ash Ponds Total Nuclear Ash Ponds Total

(Millions)

Reconciliation of ARO Liability:

 Balance as of January 1, $ 650.3 $ 352.0 $ 1,002.3 $ 280.0 $ 67.4 $ 347.4 

 Accretion expense 14.1 7.8 21.9 12.1 3.6 15.7 

 Additional layer 0.0 0.0 0.0 358.2 281.0 639.2 

 Balance as of December 31, $ 664.4 $ 359.8 $ 1,024.2 $ 650.3 $ 352.0 $ 1,002.3 

Asset Retirement Cost (ARC): $ 334.3 $ 173.1 $ 507.4 $ 334.3 $ 173.1 $ 507.4 

J - Reporting Impairment Losses - The Authority’s Board authorized the retirement of six generating units 

during 2012. December 2012 was set for the permanent retirement date for four coal-fired generating units 

(Grainger Units 1 and 2 and Jefferies Units 3 and 4). In compliance with GASB 42, the required accounting 

entries were recorded for capital assets, depreciation effect, CTBR expense, materials and supplies. 

2013 updates include a potential sale of Grainger Generating Station assets. The Authority is currently preparing

the assets to comply with requirements in the pending sales contract. In addition, sales of coal (fuel stock pile) 

from the Jefferies Generating Station began in late 2013. Sale of coal will occur at both generation sites (Jefferies 

and Grainger) going forward into 2014.
I-8

The Authority continues to implement the appropriate processes to fully close the retired units in order to remain 

in compliance with regulatory requirements. It should be noted that the closure of the ash ponds at each site will 

result in additional entries and adjustments to accumulated depreciation, asset retirement obligation (ARO) and 

various other balances in subsequent years.

K - Investment in Associated Companies - The Authority is a member of The Energy Authority (TEA). 

Approximate ownership interests were as follows:

Years Ended December 31, 2013 2012

Members Ownership (%)

 City Utilities of Springfield (Missouri) 6.7 6.7

 Cowlitz Public Utility District (Washington) 6.7 6.7

 Gainesville Regional Utilities (Florida) 6.6 6.6

 JEA (Florida) 20.0 20.0

 MEAG Power (Georgia) 20.0 20.0

 Nebraska Public Power District (Nebraska) 20.0 20.0

 Santee Cooper (South Carolina) 20.0 20.0

 Total 100.0 100.0

TEA markets wholesale power and coordinates the operation of the generation assets of its members to 

maximize the efficient use of electrical energy resources, reduce operating costs and increase operating revenues 

of the members. It is expected to accomplish the foregoing without impacting the safety and reliability of the 

electric system of each member. TEA does not engage in the construction or ownership of generation or 

transmission assets. In addition, it assists members with fuel hedging activities and acts as an agent in the 

execution of forward transactions. The Authority accounts for its investment in TEA under the equity method of 

accounting.

All of TEA’s revenues and costs are allocated to the members. The following table summarizes the transactions 

applicable to the Authority:

Years Ended December 31, 2013 2012

(Thousands)

TEA Investment:

Balance as of January 1, $ 7,932 $ 9,354 

Reduction to power costs and

 increases in electric revenues 21,322 40,813 

Less: Distributions from TEA 22,444 42,117 

Less: Other (includes equity losses) 166 118

Balance as of December 31, $ 6,644 $ 7,932

Due To/Due From TEA:

Payable to $ 29,249 $ 26,463 

Receivable from $ 1,592 $ 2,013 

The Authority’s exposure relating to TEA is limited to the Authority’s capital investment, any accounts receivable 

and trade guarantees provided by the Authority. These guarantees are within the scope of FASB ASC 952. 

Upon the Authority making any payments under its electric guarantee, it has certain contribution rights with the 

other members in order that payments made under the TEA member guarantees would be equalized ratably, 

based upon each member’s equity ownership interest. After such contributions have been affected, the Authority 

would only have recourse against TEA to recover amounts paid under the guarantee. The term of this guarantee 

is generally indefinite, but the Authority has the ability to terminate its guarantee obligations by providing advance 
I-9

notice to the beneficiaries thereof. Such termination of its guarantee obligations only applies to TEA transactions 

not yet entered into at the time the termination takes effect. The Authority’s support of TEA’s trading activities is 

limited based on the formula derived from the forward value of TEA’s trading positions at a point in time. The 

formula was approved by the Authority’s Board. At December 31, 2013, the trade guarantees are an amount not 

to exceed approximately $72.9 million.

The Authority is also a member of Colectric Partners (Colectric). Members and ownership interests were as 

follows:

Years Ended December 31, 2013 2012

Members Ownership (%)

 Florida Municipal Power Agency (Florida) N/A N/A

 Gainesville Regional Utilities (Florida) N/A N/A

 JEA (Florida) 25.0 25.0

 MEAG Power (Georgia) 25.0 25.0

 Nebraska Public Power District (Nebraska) 25.0 25.0

 Orlando Utilities Commission (Florida) N/A N/A

 Santee Cooper (South Carolina) 25.0 25.0

 Total 100.0 100.0

Colectric provides public power utilities with key project and business management resources. Colectric also 

specializes in the development, project management, operations and maintenance of public power utilities’ 

electric generation facilities and electric system infrastructure. The members may elect to participate in Colectric 

initiatives based on individual utility needs.

Currently, the Authority participates in several of Colectric’s initiatives. One involves managing the major gas 

turbine overhauls, thereby promoting the sharing of spare parts and technical expertise. Another is a strategic 

sourcing initiative, intended to achieve major cost savings through volume purchasing leverage. Other initiatives 

in which the Authority participates include steam turbine (combined cycle and non-combined cycle) gas turbine 

inlet air filters, maintenance/inspection/repair and borescope/NDT services for steam and gas turbines.

The Authority’s exposure relating to Colectric is limited to its capital investment, any accounts receivable and any 

indemnifications related to agreements between Colectric and the Authority. These indemnifications are within 

the scope of FASB ASC 952. The Authority’s initial investment in Colectric was $413,000. The balance in its 

member equity account at December 31, 2013 and 2012 was approximately $196,000 and $192,000,

respectively. Since 2001, cumulative net direct cost and direct savings have been $4.1 million and $18.1 million, 

respectively. 

On October 1, 2013, the Authority along with MEAG Power became originating members of TEA Solutions. JEA 

and Cowlitz Public Utility District joined later in 2013. TEA Solutions is a publicly supported non-profit corporation. 

TEA Solutions was formed mainly to (1) coordinate the operation of electric generation resources and the 

purchase and sale of electric power on behalf of the corporation’s clients; (2) coordinate the purchase and sale of 

natural gas relating to fuel for clients’ generation of electric energy or relating to clients’ operation of a retail gas 

distribution system; and (3) provide consulting and software services to clients.

The Authority funded its initial share of TEA Solutions with a $150,000 contribution in 2013. This contribution was 

to cover legal, consulting and other start-up costs pertaining to TEA Solutions. Neither financial statements nor 

an estimate of the Authority’s share of start-up expenses were available as of December 31, 2013. The 

Authority’s exposure relating to TEA Solutions is limited to the Authority’s capital investment, any accounts 

receivable and trade guarantees provided by the Authority. 
I-10

L – Deferred Outflows / Deferred Inflows of Resources - In addition to assets, the Combined Statements 

of Net Position reports a separate section for Deferred Outflow of Resources. These items represent a 

consumption of net position that applies to a future period and until that time will not be recognized as an expense 

or expenditure. The Authority has two items meeting this criterion: (1) accumulated decrease in fair value of 

hedging derivatives; and (2) unamortized loss on refunded and defeased debt.

In addition to liabilities, the Combined Statements of Net Position also reports a separate section for Deferred 

Inflows of Resources. These items represent an acquisition of net position that applies to a future period and until 

that time will not be recognized as revenue. The Authority has two items meeting this criterion: (1) accumulated 

increase in fair value of hedging derivatives; and (2) nuclear decommissioning costs. 

The following table summarizes the Authority’s total deferred items:

Years Ended December 31, 2013 2012

(Thousands)

Deferred Outflows of Resources $ 139,235 $ 172,963 

Deferred Inflows of Resources 193,995 199,675 

During 2013, the Authority continued to review GASB 63 requirements and found that certain items classified 

as Deferred Inflows of Resources at December 31, 2012 did not meet the criterion. The following table 

summarizes the change in classifications:

2012

Combined Statements of Net Position (Thousands)

Change:

Current liabilities

 Other current liabilities $ 8,663 

Noncurrent liabilities

 Other credits and noncurrent liabilities 45,961 

 Total $ 54,624 

Combined Statements of Net Position

Original:

Deferred inflows of resources

 Compensated absences $ 8,663 

 Unamortized gain on defeased debt 1,168 

 Unfunded pension and other post employment benefit costs 44,793 

 Total $ 54,624 
I-11

M - Accounting for Derivative Instruments - In compliance with GASB 53 and 64, the annual changes in 

the fair value of effective hedging derivative instruments are required to be deferred – reported as deferred 

outflows of resources and deferred inflows of resources on the Combined Statements of Net Position. Deferral of 

changes in fair value generally lasts until the transaction involving the hedged item ends. 

Natural gas, a core business commodity input for the Authority, has historically been hedged in an effort to 

mitigate gas cost risk by reducing cost volatility and improving cost effectiveness. Unrealized gains and losses 

related to such activity are deferred in a regulatory account and recognized in earnings as fuel costs are incurred 

in the production cycle. 

A summary of the Authority’s derivative activity for years ended December 31, 2013 and 2012 is below:

Cash Flow Hedges and Summary of Activity

Years Ended December 31, 2013 2012

Account Classification (Millions)

Fair Value 

 Natural Gas Regulatory Assets/Liabilities $ (11.5) $ (31.8)

 Crude Oil Regulatory Assets/Liabilities 0.0 0.0

 Heating Oil Regulatory Assets/Liabilities 0.2 0.3 

Changes in Fair Value

 Natural Gas Regulatory Assets/Liabilities $ 20.3 $ 23.0 

 Crude Oil Regulatory Assets/Liabilities 0.0 (1.6)

 Heating Oil Regulatory Assets/Liabilities (0.1) (1.2)

Recognized Net Gains (Losses)

 Natural Gas Operating Expense-Fuel $ (21.2) $ (41.1)

 Crude Oil Operating Expense-Fuel 0.0 2.2 

 Heating Oil Operating Expense-Fuel (0.2) (2.4)

Realized But Not Recognized Net Gains (Losses)

 Natural Gas Regulatory Assets/Liabilities $ 6.5 $ (5.9)

 Crude Oil Regulatory Assets/Liabilities 0.0 0.0

 Heating Oil Regulatory Assets/Liabilities (0.2) 0.1 

Notional

MBTUs

 Natural Gas 51,860 33,610 

Gallons (000s) 

 Heating Oil 4,620 6,468 

N - Revenue Recognition and Fuel Costs - Substantially all wholesale and industrial revenues are billed and 

recorded at the end of each month. Revenues for electricity delivered to retail customers but not billed are 

accrued monthly. Accrued revenue for retail customers totaled $14.4 million in 2013 and $13.4 million in 2012.

Fuel costs are reflected in operating expenses as fuel is consumed. Fuel expense for all customers is billed 

utilizing rates and contracts, the majority of which include fuel adjustment provisions based on either the accrued

costs for the previous month or the actual weighted average costs for the previous three-month period.
I-12

O - Bond Issuance Costs and Refunding Activity - GASB 62 requires that any gains or losses resulting 

from extinguishment of debt be expensed at the time of extinguishment. GASB 65 requires that debt issuance 

costs be expensed in the period incurred. In order to align the impact of these pronouncements with the 

Authority’s rate making process, in October 2012, the Board authorized the use of regulatory accounting to allow 

continuation of prior accounting treatment with regards to these costs. 

Consistent with prior accounting periods, unamortized debt discounts, premiums and expenses are amortized to 

income over the terms of the related debt issues. Gains or losses on refunded and extinguished debt are 

amortized to earnings over the shorter of the remaining life of the refunded debt or the life of the new debt. 

P - Distribution to the State - Any and all net earnings of the Authority not necessary for the prudent conduct 

and operation of its business in the best interests of the Authority or to pay the principal of and interest on its 

bonds, notes, or other evidences of indebtedness or other obligations, or to fulfill the terms and provisions of any 

agreements made with the purchasers or holders thereof or others must be paid over semiannually to the State 

Treasurer for the general funds of the State. Nothing in this section shall prohibit the Authority from paying to the 

State each year up to one percent of its projected operating revenues, as such revenues would be determined on 

an accrual basis, from the combined electric and water systems. (Code of Laws of South Carolina, as amended 

Section 58-31-110).

Distributions made to the State in 2013 and 2012 totaled approximately $20.4 million and $19.6 million, 

respectively.
I-13

Q - New Accounting Standards -

STATEMENT NO. & 

ISSUE DATE TITLE/SUMMARY

SUMMARY OF ACTION BY 

THE AUTHORITY

Statement No. GASB 61 The Financial Reporting Entity: Omnibus-an amendment of GASB Statements No. 

14 and No. 34

Issue Date: November 2010 Effective for Periods Beginning After: June 15, 2012

Reviewed and Adopted 

Early in 2012

Description: This is a result of a reexamination of the previous reporting entity guidance contained in 

Statement No. 14. The most significant effect is the increased emphasis on a financial 

benefit or burden between the primary government and component units.

Statement No. GASB 65 Items Previously Reported as Assets and Liabilities

Issue Date: March 2012 Effective for Periods Beginning After: December 15, 2012

Reviewed and Adopted 

Early in 2012

Description: This statement provides guidance and establishes accounting and financial reporting 

standards that reclassify, as deferred outflows of resources or deferred inflows of 

resources, certain items that were previously reported as assets and liabilities. 

Statement No. GASB 66 Technical Corrections - 2012 - an amendment of GASB Statements No. 10 and No. 

62

Issue Date: March 2012 Effective for Periods Beginning After: December 15, 2012

Reviewed and Adopted

Early in 2012

Description: This statement's objective is to improve accounting and financial reporting for a 

governmental financial reporting entity by resolving conflicting guidance that resulted from 

the issuance of two pronouncements, Statements No. 54, Fund Balance Reporting and 

Governmental Fund Type Definitions, and No. 62, Codification of Accounting and 

Financial Reporting Guidance Contained in Pre-November 30, 1989 FASB and AICPA 

Pronouncements.

Statement No. GASB 67 Financial Reporting for Pension Plans - an amendment of GASB 25

Issue Date: June 2012 Effective for Periods Beginning After: June 15, 2013

Under Review

Description: The objective of GASB 67 is to improve financial reporting by state and local 

governmental pension plans. GASB 67 results from a comprehensive review of the 

effectiveness of existing standards of accounting and financial reporting for pensions with 

regard to providing decision-useful information, supporting assessments of accountability 

and interperiod equity and creating additional transparency. GASB 67 replaces the 

requirements of Statements No. 25, Financial Reporting for Defined Benefit Pension 

Plans and Note Disclosures for Defined Contribution Plans and No. 50, Pension 

Disclosures.

Statement No. GASB 68 Accounting and Financial Reporting for Pensions - an amendment of GASB 

Statement No. 27

Issue Date: June 2012 Effective for Periods Beginning After: June 15, 2014

Under Review

Description: The primary objective of this Statement is to improve accounting and financial reporting 

by state and local governments for pensions. It also improves information provided by 

state and local governmental employers about financial support for pensions that is 

provided by other entities. 

Statement No. GASB 69 Government Combinations and Disposals of Government Operations

Issue Date: January 2013 Effective for Periods Beginning After: December 15, 2013

Under Review

Description: This statement establishes accounting and financial reporting standards related to 

government combinations and disposals of government operations. As used in this 

Statement, the term "government combinations" includes a variety of transactions referred 

to as mergers, acquisitions and transfers of operations.

Statement No. GASB 70 Accounting and Financial Reporting for Nonexchange Financial Guarantees

Issue Date: April 2013 Effective for Periods Beginning After: June 15, 2013

Under Review

Description: The objective of this statement is to improve accounting and financial reporting by state 

and local governments that extend and receive nonexchange financial guarantees. This 

Statement requires a government that extends a nonexchange financial guarantee to 

recognize a liability when qualitative factors and historical data, if any, indicate that it is 

more likely than not the government will be required to make a payment on the guarantee.

Statement No. GASB 71 Pension Transition for Contributions Made Subsequent to the Measurement Date -

an amendment of GASB Statement No. 68 

Issue Date: November 2013 The provisions of this Statement should be applied simultaneously with the provisions of 

Statement 68.

Under Review

Description: The objective of this Statement is to address an issue regarding application of the 

transition provisions of Statement No. 68, "Accounting and Financial Reporting for 

Pensions." The issue relates to amounts associated with contributions, if any, made by a 

state of local government employer or nonemployer contributing entity to a defined benefit 

pension plan after the measurement date of the government's beginning net pension 

liability.
I-14

NOTE 2 – COSTS TO BE RECOVERED FROM FUTURE REVENUE:

The Authority’s rates are established based upon debt service and operating fund requirements. Depreciation is 

not considered in the cost of service calculation used to design rates. In accordance with GASB 62, the 

differences between debt principal maturities (adjusted for the effects of premiums, discounts, expenses and 

amortization of deferred gains and losses) and depreciation on debt financed assets are recognized as CTBR. 

The recovery of outstanding amounts recorded as CTBR will coincide with the repayment of the applicable 

outstanding debt. The Authority’s summary of CTBR activity is recapped below:

Years Ended December 31, 2013 2012

(Millions)

CTBR Regulatory Asset:

 Balance $ 227.6 $ 220.2 

CTBR Expense/(Reduction to Expense):

 Net Expense $ (7.4) $ (9.2)

NOTE 3 – CAPITAL ASSETS:

Capital asset activity for the years ended December 31, 2013 and 2012 was as follows:

Beginning 

Balances Increases Decreases

Ending 

Balances

YEAR 2013

(Thousands)

Utility plant $ 6,744,928 $ 189,268 $ (23,234) $ 6,910,962 

Long lived assets-asset retirement cost 507,394 0 0 507,394 

Accumulated depreciation (2,954,471) (233,462) 37,913 (3,150,020)

 Total utility plant - net 4,297,851 (44,194) 14,679 4,268,336

Construction work in progress 1,643,507 644,343 (187,219) 2,100,631 

Other physical property - net 6,560 0 (476) 6,084 

 Totals $ 5,947,918 $ 600,149 $ (173,016) $ 6,375,051

YEAR 2012

(Thousands)

Utility plant $ 6,724,937 $ 158,260 $ (138,269) $ 6,744,928 

Long lived assets-asset retirement cost 33,078 474,316 0 507,394 

Accumulated depreciation (2,902,820) (189,796) 138,145 (2,954,471)

 Total utility plant - net 3,855,195 442,780 (124) 4,297,851 

Construction work in progress 1,230,771 1,046,049 (633,313) 1,643,507 

Other physical property - net 6,783 0 (223) 6,560 

 Totals $ 5,092,749 $ 1,488,829 $ (633,660) $ 5,947,918 
I-15

NOTE 4 – CASH AND INVESTMENTS HELD BY TRUSTEE AND 

FUND DETAILS:

All cash and investments of the Authority are held and maintained by custodians and trustees. The use of 

unexpended proceeds from sale of bonds, debt service funds and other sources is designated in accordance with 

applicable provisions of various bond resolutions, lease agreements, the Enabling Act included in the South 

Carolina Code of Laws (the Enabling Act) or by management directive. Restricted funds have constraints placed 

on their use (see Note 1-D – Restricted Assets). The use of unrestricted funds may be either designated for a 

specific use by management directive or undesignated, but are available to provide liquidity for operations as 

needed.

Following are the details of the Authority’s funds which are classified in the accompanying financial statements as 

unrestricted and restricted cash, cash equivalents and investments:

Years Ended December 31, 2013 2012 (1)

Funds

Cash & Cash 

Equivalents Investments Total

Cash & Cash 

Equivalents Investments Total

(Thousands)

Current Unrestricted:

Capital Improvement $ 40,798 $ 85,154 $ 125,952 $ 29,032 $ 44,696 $ 73,728 

Debt Reduction 5,201 49,473 54,674 1,656 51,677 53,333 

Funds from Taxable Borrowings 10,780 229,403 240,183 70,155 84,016 154,171 

General Improvement 413 2,461 2,874 1,412 1,450 2,862 

Internal Nuclear Decommissioning Fund 846 73,595 74,441 4,262 76,691 80,953 

Nuclear Fuel 1,010 1,000 2,010 8,015 3,051 11,066 

Revenue and Operating 89,103 31,999 121,102 73,959 25,171 99,130 

Special Reserve 24,587 53,499 78,086 15,100 48,301 63,401 

Total $ 172,738 $ 526,584 $ 699,322 $ 203,591 $ 335,053 $ 538,644 

Current Restricted:

Debt Service Funds $ 74,551 $ 118,270 $ 192,821 $ 119,603 $ 128,900 $ 248,503 

Funds from Tax-exempt Borrowings 89,250 622,466 711,716 118,598 196,505 315,103 

Other 18,654 21,914 40,568 35,341 16,786 52,127 

Total $ 182,455 $ 762,650 $ 945,105 $ 273,542 $ 342,191 $ 615,733 

Noncurrent Restricted:

External Nuclear Decommissioning Trust $ 1,535 $ 109,060 $ 110,595 $ 1,911 $ 112,535 $ 114,446 

Total $ 1,535 $ 109,060 $ 110,595 $ 1,911 $ 112,535 $ 114,446 

TOTAL FUNDS $ 356,728 $ 1,398,294 $ 1,755,022 $ 479,044 $ 789,779 $ 1,268,823 

Cash and investments as of December 31, consisted of the following:

 Cash/Deposits $ 60,394 $ 75,905 

 Investments 1,694,628 1,192,918 

 Total cash and investments $ 1,755,022 $ 1,268,823 

(1) The Authority’s management determined a need for a change in the policy regarding the criteria for unrestricted and restricted cash and 

investments. This resulted in material changes to the classification of those funds as reported in 2012. Details of the revised fund criteria are 

defined below.
I-16

Current Unrestricted Funds – These funds are used for operating activities for the Authority’s respective 

systems. Although funds are segregated per management directive based on their intended use, since no 

restrictions apply, the funds are available to provide additional liquidity for operations. Included in this category is 

the internal Nuclear Decommissioning Fund intended by management to be used to offset future nuclear 

decommissioning costs but represents amounts in excess above the mandated Nuclear Regulatory Commission 

(NRC) decommissioning requirement which is funded separately in an external Nuclear Decommissioning Trust. 

Also included are funds from taxable borrowings intended to be used for both capital construction costs and for 

working capital purposes, as expected at the time proceeds are borrowed.

Current Restricted Funds – These funds are restricted in their allowed use. Debt service funds are restricted 

for payment of principal and interest debt service on outstanding debt. Funds from tax-exempt borrowings are 

intended to be used for capital construction costs as expected at the time proceeds are borrowed and are 

restricted pursuant to sections of both the U.S. Treasury Regulations and the Internal Revenue Code that govern 

the use of tax-exempt debt. Other funds are restricted for other special purposes. 

Noncurrent Restricted Funds – These funds are restricted as to their specific use. The external Nuclear 

Decommissioning Trust is restricted for future nuclear decommissioning costs and represents the mandated NRC 

funding requirements.

The Authority’s investments are authorized by the Enabling Act, the Authority’s investment policy and the 

Revenue Obligation Resolution. Authorized investment types include Federal Agency Securities, State of South 

Carolina General Obligation Bonds and U.S. Treasury Obligations, all of which are limited to a 10 year maximum 

maturity in all portfolios, except the decommissioning funds. Certificate of Deposits and Repurchase Agreements 

are also authorized with a maximum maturity of one year.

All debt securities are recorded at their fair value with gains and losses in fair value reflected as a component of 

non-operating income in the Combined Statements of Revenues, Expenses and Changes in Net Position. 

The Authority’s investment activity in all fund categories is summarized as follows:

Years Ended December 31, 2013 2012

Total Portfolio (Billions)

 Total Investments $ 1.7 $ 1.2 

 Purchases 55.0 52.1 

 Sales 54.5 51.9 

Nuclear Decommissioning Portfolios (Millions)

 Total Investments $ 185.0 $ 195.4 

 Purchases 588.3 624.0 

 Sales 583.1 618.9 

 Unrealized Holding Gains 7.3 26.8

Repurchase Agreements (1) (Millions)

 Balance at December 31 $ 238.6 $ 348.1 

(1) Securities underlying repurchase agreements must have a market value of at least 102 

percent of the cost of the repurchase agreement and are delivered by broker/dealers to 

the Authority's custodial agents.
I-17

Common deposit and investment risks related to credit risk, custodial credit risk, concentration of credit risk, interest 

rate risk and foreign currency risk are as follows:

Risk Type Exposure

Credit Risk - Risk that an issuer of an 

investment will not fulfill its obligation 

to the holder of the investments. 

Measured by the assignment of rating 

by a nationally recognized statistical 

rating organization.

As of December 31, 2013 and 2012, all of the agency securities held by the Authority were rated AAA 

by Fitch Ratings, Aaa by Moody's Investors Service, Inc. and AA+ by Standard & Poor's Rating 

Services.

Custodial Credit Risk-Investments -

Risk that, in the event of the failure of 

the counterparty to a transaction, an 

entity will not be able to recover the 

value of its investment or collateral 

securities that are in the possession of 

another party.

As of December 31, 2013 and 2012, all of the Authority's investment securities are held by the Trustee 

or Agent of the Authority and therefore, there is no custodial risk for investment securities.

Custodial Credit Risk-Deposits -

Risk that, in the event of the failure of 

a depository financial institution, an 

entity will not be able to recover its 

deposits or will not be able to recover 

collateral securities that are in the 

possession of an outside party.

At December 31, 2013 and 2012, the Authority had exposure to custodial credit risk for deposits as 

follows:

Depository Account Type

Bank Balance

Years Ended December 31, 2013 2012

(Thousands)

Uninsured and collateral held by Bank's agent

 not in Authority's name $ 0 $ 500 

Concentration of Credit Risk - The 

investment policy of the Authority 

contains no limitations on the amount 

that can be invested in any one issuer. 

Investments in any one issuer (other than U. S. Treasury securities) that represent five percent or more 

of total Authority investments at December 31, 2013 and 2012 were as follows: 

Security Type / Issuer Fair Value

2013 2012

Federal Agency Fixed Income Securities (Thousands)

Federal Home Loan Bank $ 465,448 $ 475,406 

Federal National Mortgage Association 255,042 98,068 

Federal Farm Credit Bank 215,631 173,162 

Federal Home Loan Mortgage Corp 416,540 22,911 

Interest Rate Risk - Risk that 

changes in market interest rates will 

adversely affect the fair value of an 

investment. Generally, the longer the 

maturity of an investment, the greater 

the sensitivity of its fair value to 

changes in market interest rates.

The Authority manages its exposure to interest rate risk by investing in securities that mature as 

necessary to provide the cash flow and liquidity needed for operations. The following table shows the 

distribution of the Authority's investments by maturity at December 31, 2013 and 2012: 

2013 2012

Investment Type:

Fair Value 

(Thousands)

Weighted 

Average 

Maturity 

(Years)

Fair Value 

(Thousands)

Weighted 

Average 

Maturity 

(Years)

Certificates of Deposits $ 1,450 0.21 $ 1,450 0.21

Federal Agency Discount Notes 508,489 0.24 199,858 0.01

Federal Agency Securities 867,850 3.09 594,291 3.56

Repurchase Agreements 238,599 0.01 348,139 0.01

U.S. Treasury Notes and Strips 78,239 4.02 49,180 7.67

 Total $ 1,694,627 $ 1,192,918 

Portfolio Weighted Average Maturity 1.88 1.94

The Authority holds zero coupon bonds which are highly sensitive to interest rate fluctuations in both 

the Nuclear Decommissioning Trust and Nuclear Decommissioning Fund. Together these accounts 

hold $56.5 million par in U.S. Treasury Strips ranging in maturity from May 15, 2014 to May 15, 2039. 

The accounts also hold $57.0 million par in government agency zero coupon securities in the two 

portfolios ranging in maturity from November 15, 2014 to April 15, 2030. Zero coupon bonds or U.S. 

Treasury Strips are subject to wider swings in their market value than coupon bonds. These portfolios 

are structured to hold these securities to maturity or early redemption. The Authority has a buy and 

hold strategy for these portfolios. Based on the Authority’s current decommissioning assumptions, it is 

anticipated that no funds will be needed any earlier than 2043. The Authority has no other investments 

that are highly sensitive to interest rate fluctuations.

Foreign Currency Risk - Risk exists 

when there is a possibility that 

changes in exchange rates could 

adversely affect investment or deposit 

fair market value.

The Authority is not authorized to invest in foreign currency and therefore has no exposure.
I-18

NOTE 5 – LONG-TERM DEBT:

Debt Outstanding

The Authority's long-term debt at December 31, 2013 and 2012 consisted of the following:

2013 2012 Interest Rate(s) (1) Call Price (2)

(Thousands) (%) (%)

Capitalized Lease Obligations: (mature through 2014) $ 244 $ 1,227 5.00 N/A

Revenue Obligations: (mature through 2053)

 1999 Taxable Series B 1,700 3,280 7.42 Non-callable

 2002 Refunding Series A 0 12,190 N/A N/A

 2002 Refunding Series D 0 36,500 N/A N/A

 2003 Refunding Series A 10,870 255,880 4.75 100

 2004 Tax-exempt Series A 45,610 55,720 5.00 100

 2004 Taxable Series B 6,365 9,350 4.47-4.52 P&I Plus Make-Whole Premium

 2004 Series M (4) 30,031 29,786 4.25-5.00 100/Accreted Value

 2005 Refunding Series A 125,295 125,295 5.25-5.50 100

 2005 Refunding Series B 222,725 232,080 5.00 100

 2005 Refunding Series C 78,150 78,150 4.125-4.75 100

 2005 Series M (4) 12,701 12,515 3.65-4.35 100/Accreted Value

 2006 Tax-exempt Series A 432,475 442,475 3.625-5.00 100

 2006 Taxable Series B 59,500 73,250 5.00-5.05 P&I Plus Make-Whole Premium

 2006 Series M (4) 7,811 10,283 3.75-4.20 100/Accreted Value

 2006 Refunding Series C 114,755 114,755 4.00-5.00 100

 2007 Series A 290,175 303,005 4.00-5.00 100

 2007 Refunding Series B 82,855 97,970 4.00-5.00 Non-callable

 2008 Tax-exempt Series A 391,985 391,985 5.00-5.75 100

 2008 Taxable Series B 25,000 260,000 6.808-8.368 P&I Plus Make-Whole Premium

 2008 Series M (4) 20,901 25,083 3.00-4.80 100/Accreted Value

 2009 Tax-exempt Refunding Series A 84,605 85,640 3.00-5.00 100

 2009 Tax-exempt Series B 160,075 162,285 4.00-5.25 100

 2009 Taxable Series C 86,970 87,040 4.12-6.224 P&I Plus Make-Whole Premium

 2009 Tax-exempt Refunding Series D 0 10,500 N/A N/A

 2009 Tax-exempt Series E 215,755 250,965 3.00-5.00 100

 2009 Taxable Series F 100,000 100,000 5.74 P&I Plus Make-Whole Premium

 2010 Series M1(4) 27,806 28,400 1.35-4.30 100/Accreted Value

 2010 Refunding Series B 220,665 231,060 3.00-5.00 100

 2010 Series M2 (4) 17,361 17,233 1.60-3.875 100/Accreted Value

 2010 Series C (Build America Bonds) (3) 360,000 360,000 6.454 P&I Plus Make-Whole Premium

 2011 Series M1 (4) 26,655 26,471 2.00-4.80 100/Accreted Value

 2011 Taxable Series A (LIBOR Index Bonds) 0 316,632 N/A N/A

 2011 Refunding Series B 282,700 288,515 4.00-5.00 Non-callable

 2011 Refunding Series C 135,855 135,855 4.375-5.00 100

 2011 Series M2 (4) 21,935 21,923 1.40-4.20 100/Accreted Value

 2012 Refunding Series A 98,610 98,610 3.00-5.00 100

 2012 Refunding Series B 25,200 32,325 5.00 Non-callable

 2012 Refunding Series C 95,305 119,145 5.00 Non-callable

 2012 Tax-exempt Series D 310,120 312,160 3.00-5.00 100

 2012 Taxable Series E 262,830 262,830 3.572-4.551 P&I Plus Make-Whole Premium

 2012 Series M1 (4) 21,124 21,220 1.40-4.00 100/Accreted Value

 2012 Series M2 (4) 18,301 18,205 1.10-3.70 100/Accreted Value

2013 Series M1 (4) 23,366 0 1.30-3.90 100/Accreted Value

2013 Tax-exempt Series A 252,655 0 5.00-5.75 100

2013 Tax-exempt Refunding Series B 388,730 0 5.00-5.125 100

2013 Taxable Series C 250,000 0 5.78 P&I Plus Make-Whole Premium

2013 Taxable Series D (LIBOR Index Bonds) 450,000 0

1 Month LIBOR 

plus 0.875-1.10 100

2013 Tax-exempt Series E 506,765 0 5.00-5.50 100

 Total Revenue Obligations 6,402,292 5,556,566

Other Long-Term Obligations: (mature through 2016) 44,956 0 N/A N/A

Less: Current Portion - Long-term Debt 133,671 334,842

Total Long-term Debt - (Net of current portion) $ 6,313,821 $ 5,222,951

(1) Interest Rates apply only to bonds outstanding as of December 31, 2013.

(2) Call Price may only apply to certain maturities outstanding at December 31, 2013.

(2) These bonds were issued as "Build America Bonds" under the American Recovery and Reinvestment Act of 2009 and are eligible to receive an interest 

subsidy payment from the United States Department of Treasury in an amount up to 35% of interest payable on the bonds.

(3) Includes Current Interest Bearing Bonds (CIBS) and Capital Appreciation Bonds (CABS).
I-19

Changes in Long-Term Debt

Long-term debt (LTD) activity for the years ended December 31, 2013 and 2012 was as follows:

Gross LTD 

Beginning 

Balances Increases Decreases

Gross LTD 

Ending

Balances

Current 

Portion 

LTD

Net LTD 

Ending 

Balances

YEAR 2013

(Thousands)

Capitalized Lease Obligations $ 1,227 $ 0 $ (983) $ 244 $ 244 $ 0 

Other Long-Term Obligations 0 44,956 0 44,956 0 44,956 

Revenue Obligations 5,556,566 1,873,808 (1,028,082) 6,402,292 133,427 6,268,865

 Totals $ 5,557,793 $ 1,918,764 $ (1,029,065) $ 6,447,492 $ 133,671 $ 6,313,821

YEAR 2012

(Thousands)

Capitalized Lease Obligations $ 2,469 $ 0 $ (1,242) $ 1,227 $ 982 $ 245 

Revenue Obligations 5,158,481 867,277 (469,192) 5,556,566 333,860 5,222,706 

 Totals $ 5,160,950 $ 867,277 $ (470,434) $ 5,557,793 $ 334,842 $ 5,222,951 

Summary of Long-Term Principal and Interest

Maturities and projected interest payments of long-term debt are as follows:

PRINCIPAL INTEREST

Capitalized Other Capitalized

Lease Long-Term Revenue Total Lease Revenue Total 

Obligations Obligations Obligations Principal Obligations Obligations (2) Interest (2) TOTAL

Years Ending 

December 31, (Thousands)

2014 (1) $ 244 $ 0 $ 121,775 $ 122,019 $ 7 $ 312,201 $ 312,208 $ 434,227 

2015 (1) 0 0 555,502 555,502 0 296,367 296,367 851,869 

2016 (1) 0 44,956 333,878 378,834 0 283,381 283,381 662,215 

2017 0 0 242,690 242,690 0 270,291 270,291 512,981 

2018 0 0 191,822 191,822 0 260,770 260,770 452,592 

2019-2023 0 0 974,581 974,581 0 1,155,976 1,155,976 2,130,557 

2024-2028 0 0 670,884 670,884 0 972,057 972,057 1,642,941 

2029-2033 0 0 757,025 757,025 0 802,882 802,882 1,559,907 

2034-2038 0 0 848,755 848,755 0 590,684 590,684 1,439,439 

2039-2043 0 0 838,615 838,615 0 380,331 380,331 1,218,946 

2044-2048 0 0 492,600 492,600 0 194,209 194,209 686,809 

2049-2053 0 0 374,165 374,165 0 51,177 51,177 425,342 

Total $ 244 $ 44,956 $ 6,402,292 $ 6,447,492 $ 7 $ 5,570,326 $ 5,570,333 $ 12,017,825 

(1) Years 2014 - 2016 include projected interest for 2013 Taxable Series D (LIBOR Index Bonds).

(2) Does not reflect impact of subsidy interest payments on 2010 Series C (Build America Bonds). 
I-20

Summary of Refunded and Defeased Bonds Outstanding and Unamortized Losses

Refunded and defeased bonds outstanding, original loss on refunding and the unamortized loss at December 31, 2013 are as follows:

Refunded and 

Refunding Refunded Defeased Bonds Original Unamortized

Issue Bonds Outstanding Loss Loss

(Thousands)

Cash Defeasance $ 20,000 1982 Series A $ 0 $ 2,763 $ 626 

Commercial Paper $ 76,050 1973 Series

105,605 1977 Series

81,420 1978 Series 0 2,099 91 

2003 Refunding Series A $ 336,385 1993 Refunding Series C

15,750 1995 Refunding Series A 0 57,064 886 

2005 Refunding Series A $ 74,970 1995 Refunding Series A

37,740 1995 Refunding Series B

20,080 1996 Refunding Series A 0 23,864 8,496 

2005 Refunding Series B $ 2,590 1995 Refunding Series A

100,320 1995 Refunding Series B

192,305 1996 Refunding Series A

21,505 1996 Refunding Series B 0 73,749 29,932 

2005 Refunding Series C $ 86,335 1993 Refunding Series C 0 12,125 6,433 

2006 Refunding Series C $ 105,005 1999 Series A

10,000 2002 Series B 0 7,054 569 

2007 Refunding Series B $ 105,370 1997 Refunding Series A 0 8,832 2,430 

2009 Refunding Series A $ 99,515 1997 Refunding Series A

20,125 1998 Refunding Series B 0 8,707 6,194 

2010 Refunding Series B $ 30,430 2001 Series A

118,600 2002 Series B

84,780 2002 Refunding Series D 0 22,954 13,854 

2011 Refunding Series B $ 8,990 2002 Refunding Series D

291,825 2004 Series A 286,425 23,287 16,154 

2011 Refunding Series C $ 134,715 2002 Series B

5,160 2007 Series A 0 4,362 3,954 

2012 Refunding Series A $ 73,535 2003 Refunding Series A

34,160 2004 Series A 34,160 12,206 10,057 

Feb 2012 Defeasance $ 5,615 2003 Refunding Series A 0 749 676 

2013 Refunding Series B $ 209,426 2003 Refunding Series A

7,070 2004 Series A

5,000 2006 Series A

6,565 2007 Series A

82,605 2008 Series B

1,125 2009 Series B

30,158 2011 Series A (LIBOR Index)

2,040 2012 Series D 19,760 14,446 14,252 

2013 Refunding Series C $ 35,584 2003 Refunding Series A

97,695 2008 Series B 0 4,601 4,524 

2013 Taxable Series D (LIBOR Index) $ 54,700 2008 Series B

138,159 2011 Series A (LIBOR Index)

8,000 2012 Refunding Series C 0 920 740 

 Total $ 340,345 $ 279,782 $ 119,868 
I-21

Analysis of Prior Year Current Portion of Long-term 

As a part of its long-term capital structure plan, the Authority will be involved in a multi-year refinancing plan. As a 

result, each year certain maturities classified as current portion of long-term debt may be refinanced in the 

subsequent year prior to the maturity date. Below is an analysis of the 2012 current portion of long-term debt 

showing the amounts paid as debt service in 2013 and the amount refinanced. The remaining amount represents 

five percent of the original principal for all outstanding minibond issues.

Analysis of December 31, 2012 Current Portion of Long-term Debt: (Thousands)

Principal debt service paid from 2013 Revenues $ 166,393

Refinanced and other:

 2013 maturities refinanced 158,355 

 5% current portion requirement for original minibond issue amount (1) 10,094 

 Total $ 334,842

(1) Represents five percent annual cap on the requirement related to put features on all outstanding minibond 

issues. This is an accounting entry only and does not impact debt service.

An analysis of the $158,024 current portion of long-term debt at December 31, 2011 showed that $149,502 was 

debt service paid from 2012 Revenues with the remaining $8,522 representing five percent of the original principal 

for outstanding minibond issues.

Reconciliations of Interest Charges

Years Ended December 31, 2013 2012

(Thousands) 

Reconciliation of interest cost to interest expense:

Total interest cost $ 278,274 $ 264,140

Capitalized interest (32,751) 0 

Deferred interest expense (22,351) (46,732)

Interest charged to fuel expense (2,105) (1,994)

 Total interest expense $ 221,067 $ 215,414

Reconciliation of interest cost to interest payments:

Total interest cost $ 278,274 $ 264,140

Accrued interest - current year (100,159) (108,465)

Accrued interest - prior year 108,465 115,735

Interest released by refundings (5,030) (3,641)

Accretion on capital appreciation minibonds (2,402) (2,087)

 Total interest payments $ 279,148 $ 265,682
I-22

Debt Service Coverage

Years Ended December 31, 2013 2012 

 (Thousands) 

Operating revenues $ 1,816,576 $ 1,887,797 

Other income 9,246 12,304

Total revenues and income 1,825,822 1,900,101

Operating expenses (1,524,182) (1,571,480)

Depreciation 196,812 187,382 

Total expenses (1,327,370) (1,384,098)

Funds available for debt service prior to distribution to the State 498,452 516,003

Distribution to the State (20,394) (19,617)

Funds available for debt service after distribution to the State $ 478,058 $ 496,386

Debt Service on Accrual Basis:

Principal on long-term debt $ 117,994 $ 142,765 

Interest on long-term debt 221,067 215,414 

Interest on long-term debt paid from borrowed proceeds (12,720) 0 

Long-term debt service paid from Revenues 326,341 358,179 

Commercial paper and other principal and interest 6,670 5,914 

Total debt service paid from Revenues $ 333,011 $ 364,093 

Debt Service Coverage Ratio:

Excluding commercial paper and other:

Prior to distribution to the State 1.52 1.44 

After distribution to the State 1.46 1.38 

Including commercial paper and other:

Prior to distribution to the State 1.49 1.41 

After distribution to the State 1.43 1.36 
I-23

The fair value of the Authority’s debt is estimated based on quoted market prices for the same or similar issues or 

on the current rates offered to the Authority for debt with the same remaining maturities. Based on the borrowing 

rates currently available to the Authority for debt with similar terms and average maturities, the fair value of debt 

was $7.0 billion and $6.6 billion at December 31, 2013 and 2012, respectively.

Bond market transactions for the year ended December 31, 2013 were as follows:

Revenue Obligations, 2013 Series M1

Par 

Amount: $23,254,800 

Date 

Authorized: May 1, 2013

 Summary: - Issued Current Interest Bearing Bonds in $500 denominations and Capital Appreciation Bonds in $200 denominations

 - Issued directly by the Authority to residents of the State, customers of the Authority, members of electric cooperatives

organized under the laws of the State and electric customers of the City of Bamberg and City of Georgetown

 - Interest rates range from 1.30 percent in 2018 and 3.90 percent in 2033

Revenue Obligations, 2013 Tax-exempt Series A, 

Refunding Series B & Taxable Series C

Par 

Amount: $891,385,000 

Date 

Authorized: Aug 8, 2013

 Summary: - Issued on Aug 21, 2013 at an all-in true interest cost of 5.46 percent

- Maturities between Dec 1, 2033 and Dec 1, 2043

Revenue Obligations, 2013 Tax-exempt Series E

Par 

Amount: $506,765,000 

Date 

Authorized: Sep 26, 2013

 Summary: - Issued on Oct 4, 2013 at an all-in true interest cost of 5.34 percent

- Maturities between Dec 1, 2048 and Dec 1, 2053

As of December 31, 2013 and 2012, the Authority was in compliance with all debt covenants. The Authority’s 

bond indentures provide for certain restrictions, the most significant of which are:

(1)the Authority covenants to establish rates sufficient to pay all debt service, required lease payments, 

capital improvement fund requirements and all costs of operation and maintenance of the Authority’s 

electric and water systems and all necessary repairs, replacements and renewals thereof; and

(2)the Authority is restricted from issuing additional parity bonds unless certain conditions are met. 

All Authority debt (Electric and Water Systems) issued pursuant to the Revenue Obligation Resolution is payable 

solely from and secured by a lien upon and pledge of the applicable Electric and Water Revenues of the 

Authority. Revenue Obligations are senior to: 

(1) payment of expenses for operating and maintaining the Systems; 

(2) payments for debt service on capitalized leases;

(3) payments for debt service on commercial paper; and

(4) payments made into the Capital Improvement Fund.

Bonds Outstanding Summary 

As of December 31, 2013 2012

Outstanding Revenue Obligations $6.4 Billion $5.6 Billion

Estimated remaining interest payments $5.6 Billion $3.7 Billion

Issuance Years (inclusive) 1999 through 2013 1999 through 2012

Maturity Years (inclusive) 2014 through 2053 2013 through 2050

Note: Proceeds from these bonds were/will be used to fund a portion of the Authority’s ongoing capital 

program or retire or refund certain outstanding debt of the Authority.
I-24

NOTE 6 – VARIABLE RATE DEBT:

The Board has authorized the issuance of variable rate debt not to exceed 20 percent of the aggregate Authority 

debt outstanding (including commercial paper) as of the last day of the most recent fiscal year for which audited 

financial statements of the Authority are available. At December 31, 2013, 12 percent of the Authoirty’s aggregate 

debt outstanding was variable rate. The lien and pledge of Revenues securing variable rate debt issued as 

Revenue Obligations is senior to that securing commercial paper.

On August 8, 2013, the Board authorized the sale of approximately $450.0 million in Revenue Obligations, 2013 

Series D (LIBOR Index Bonds) (2013D Bonds). The 2013D Bonds were issued August 21, 2013 and will bear 

interest from their delivery date and will be payable on the first business day of each month. The 2013D Bonds 

will mature on June 1, 2015 and June 1, 2016. The interest rate is variable and is set monthly based on the 

London Interbank Offered Rate (LIBOR) plus 87.5 basis points, and 110.0 basis points, respectively.

Commercial paper is issued for valid corporate purposes with a term not to exceed 270 days. The information 

related to commercial paper was as follows:

Years Ended December 31, 2013 2012

Commercial paper outstanding (000's) $ 372,073 $ 329,283 

Effective interest rate (at December 31) 0.13% 0.20%

Average annual amount outstanding (000's) $ 374,497 $ 318,270 

Average maturity 45 Days 50 Days

Average annual effective interest rate 0.17% 0.19%

At December 31, 2013 and 2012, the Authority had Revolving Credit Agreements with Barclays Bank PLC, J.P. 

Morgan Chase Bank, N.A., TD Bank, N.A., U.S. Bank, N.A., and Wells Fargo Bank, N.A. totaling $800.0 million

and $700.0 million, respectively. These agreements are used to support the Authority’s issuance of commercial 

paper. There were no borrowings under the agreements during 2013 or 2012. 

NOTE 7 – SUMMER NUCLEAR STATION:

Unit 1 - The Authority and South Carolina Electric and Gas (SCE&G) are parties to a joint ownership agreement 

providing that the Authority and SCE&G shall own Unit 1 at the V.C. Summer Nuclear Station with undivided 

interests of 33 1/3 percent and 66 2/3 percent, respectively. SCE&G is solely responsible for the design, 

construction, budgeting, management, operation, maintenance and decommissioning of Unit 1 and the Authority 

is obligated to pay its ownership share of all costs relating thereto. The Authority receives 33 1/3 percent of the 

net electricity generated. In 2004, the NRC granted a twenty-year extension to the operating license for Unit 1, 

extending it to August 6, 2042.

Authority's Share of V. C. Summer Station - Unit 1

Years Ended December 31, 2013 2012

(Millions)

Plant balances before depreciation $ 515.9 $ 514.1 

Accumulated depreciation 326.7 319.2 

Operation & maintenance expense 90.2 81.6 

Nuclear fuel costs are being amortized based on energy expended using the unit-of-production method. Costs 

include a component for estimated disposal expense of spent nuclear fuel. This amortization is included in fuel 

expense and recovered through the Authority’s rates.
I-25

In 2002, SCE&G commenced a re-racking project of the on-site spent fuel pool. The new pool storage capability 

will permit full core off-load through 2017. SCE&G has signed contracts with HOLTEC International, The Shaw

Group, Inc. and Westinghouse Electric Company, Inc. (Westinghouse) to build a licensed Independent Spent Fuel 

Storage Installation (ISFSI) to commence receiving fuel in 2015. 

The NRC requires a licensee of a nuclear reactor to provide minimum financial assurance of its ability to 

decommission its nuclear facilities. In compliance with the applicable NRC regulations, the Authority established 

an external trust fund and began making deposits into this fund in September 1990. In addition to providing for 

the minimum requirements imposed by the NRC, the Authority makes deposits into an internal fund in the amount 

necessary to fund the difference between a site-specific decommissioning study completed in 2012 and the 

NRC’s imposed minimum requirement. Based on these estimates, the Authority’s one-third share of the 

estimated decommissioning costs of Unit 1 equals approximately $315.1 million in 2012 dollars. As deposits are 

made, the Authority debits FERC account 532 - Maintenance of Nuclear Plant, an amount equal to the deposits 

made to the internal and external trust funds. These costs are recovered through the Authority’s rates. 

Based on current decommissioning cost estimates, these funds, which totaled approximately $185.0 million 

(adjusted to market) at December 31, 2013, along with future deposits into the external decommissioning trust 

and investment earnings, are estimated to provide sufficient funds for the Authority’s one-third share of the total 

decommissioning costs. 

Units 2 and 3 - The Authority and SCE&G are constructing and planning to operate two additional nuclear 

generating units (Summer Units 2 and 3) at V.C. Summer Nuclear Station and submitted an application to the 

NRC in March 2008 for a combined Construction and Operating License (COL) for each of the two new units. On 

May 22, 2008, the Authority’s Board authorized the Authority to execute a Limited Agency Agreement appointing 

SCE&G to act as the Authority’s agent in connection with the performance of an Engineering, Procurement and 

Construction (EPC) Agreement. On May 23, 2008, SCE&G, acting for itself and as agent for the Authority, 

entered into an EPC Agreement with Westinghouse and Stone & Webster, Inc., (a subsidiary of The Shaw Group, 

Inc.), for the engineering, procurement and construction of two 1,100 MW nuclear generating units. Chicago 

Bridge & Iron Company acquired The Shaw Group, Inc. in February 2013. 

On October 20, 2011, the Authority and SCE&G entered into a Design and Construction Agreement. Among 

other things, the Design and Construction Agreement allows either or both parties to withdraw from the project 

under certain circumstances. Also on October 20, 2011, the Authority and SCE&G entered into an Operating and 

Decommissioning Agreement with respect to the two units. Both the Design and Construction Agreement and the 

Operating and Decommissioning Agreement define the conditions under which the Authority or SCE&G may 

convey an undivided ownership interest in the new units to a third party. Together the Design and Construction 

Agreement and the Operating and Decommissioning Agreement provide for a 45 percent ownership interest by 

the Authority in each of the two new units and replace the Amended and Restated Bridge Agreement which had 

governed the relationship between the Authority and SCE&G.

The Authority received the COLs on March 30, 2012. On April 5, 2012, the Authority’s Board authorized the 

Authority to expend up to $4.9 billion to fund the Authority’s share of the EPC Agreement and associated Owner’s 

Costs to complete the project. Construction is progressing and the following significant milestones were 

completed in 2013:

Month 

Completed Unit(s) Milestones

January 2 & 3 Energized Switchyard

March 2 Placed Nuclear Island Basemat (First Nuclear Concrete)

April 2 Set Module CR10 (Containment Vessel Bottom Head Support)

May 2 Set Containment Vessel Bottom Head

September 2 Set Structural Module CA04 (Reactor Vessel Cavity)

November 3 Placed Nuclear Island Basemat (First Nuclear Concrete)

The Authority anticipates that Unit 2 will go into service in early 2018, and Unit 3 will go into service approximately 

one year later.
I-26

As part of its capital improvement program, the Authority has evaluated its level of participation in the new units. 

Due to developments since initiation of the project, the Authority is taking actions necessary to reduce its 45 

percent ownership interest. Beginning 2011, the Authority deferred a portion of interest expense representing the 

amount related to the assumed ownership reduction. In 2013, the Authority continued deferring and began 

capitalizing portions of related interest expense based on revised ownership assumptions.

NOTE 8 – LEASES: 

The Authority has remaining capital lease contracts with Central Electric Power Cooperative, Inc. (Central), 

covering transmission and various other facilities. The remaining lease term is for one year. Quarterly lease 

payments are based on a sum equal to the interest on and principal of Central’s indebtedness to the Rural Utilities 

Service for funds borrowed to construct the above mentioned facilities. The Authority has options to purchase the 

leased properties at any time during the period of the lease agreements for an amount equal to Central’s 

indebtedness remaining outstanding on the properties at the time the options are exercised or to return the 

properties at the termination of the lease. The Authority plans to exercise each and every option to acquire 

ownership of such facilities prior to expiration of the leases.

Total minimum lease payments on Central leases at December 31, 2013 are as follows:

Year Ending December 31, (Thousands)

2014 $ 251 

Less amounts representing interest 7 

Principal payments $ 244 

Information related to property under capital leases and operating lease payments follows:

Years Ended December 31, 2013 2012

(Millions)

Property under capital leases:

 Property balances $ 10.2 $ 20.3 

 Accumulated depreciation 8.7 18.0 

Operating lease payments (1) 1.7 3.0 

(1) Includes periodic leased coal car expenses which are initially reflected in fuel

 inventory and subsequently reported in fuel expense based on tons burned.

Expiration term of current coal car leases: (2) March 2014 

(2) The maximum amount due for coal car leases for 2013 and 2014 are $445,200 and

$111,300, respectively.

Hydroelectric generating facility lease:

 - Automatically extended for five-year periods

 - May be terminated by either party by giving a two-year notice

 - Obligation is $600,000 per year plus operating expenses
I-27

NOTE 9 – CONTRACTS WITH ELECTRIC POWER COOPERATIVES:

Central is a generation and transmission cooperative that provides wholesale electric service to each of the 20

distribution cooperatives which are members of Central. Power supply and transmission services are provided to 

Central in accordance with a power system coordination and integration agreement (the Coordination 

Agreement). Under this agreement, the Authority is the predominant supplier of energy needs for Central,

excluding energy Central receives from the Southeastern Power Administration (SEPA), minimal amounts 

provided by Broad River Electric Cooperative’s ownership interest in a small run of the river hydroelectric plant

and negligible amounts purchased from others. 

Central, under the terms of the Coordination Agreement, has the right to audit costs billed to them through the

Coordination Agreement. Any differences found as a result of this process are accrued if they are probable and 

estimable. To the extent that differences arise, prospective adjustments are made to the cost of service and are 

reflected in operating revenues in the accompanying Combined Statements of Revenues, Expenses and 

Changes in Net Position. Such adjustments in 2013 and 2012 were not material to the Authority’s overall 

operating revenue.

In September 2009, the Authority and Central entered into an agreement which, among other things, would permit 

Central to purchase the electric power and energy requirements necessary to serve five of its member 

cooperatives located in the upper part of the State that were formerly members of Saluda: Blue Ridge Electric 

Cooperative, Inc., Broad River Electric Cooperative, Inc., Laurens Electric Cooperative, Inc., Little River Electric 

Cooperative, Inc. and York Electric Cooperative, Inc. (the Upstate Load) from a supplier other than the Authority. 

The Upstate Load began transitioning to the new supplier in 2013. The transition will continue through 2019 and 

will amount to approximately 1,000 MW.

In April and May 2013, the Central and Authority Boards, respectively, approved an Amendment to the Central 

Agreement (the Amended Central Agreement). This amendment provides that both parties waive their rights to 

terminate the agreement until at least December 31, 2058. The Amended Central Agreement provides for closer 

cooperation on planning of future resources, gives Central the ability to “opt-out” of future generation resources, 

and provides for cost recovery of all resources completed or under construction as of the amendment effective 

date, including V. C. Summer Units 2 and 3.

NOTE 10 – COMMITMENTS AND CONTINGENCIES:

Budget – The Authority’s 2014 three-year capital budget is as follows:

Years Ending December 31, 2014 2015 2016

(Millions)

V.C. Summer Units 2 and 3 (1) $ 583.0 $ 528.6 $ 626.0 

Environmental Compliance 39.1 48.9 30.7 

General Improvements 207.8 198.8 189.9 

Total Capital Budget (2) $ 829.9 $ 776.3 $ 846.6 

Budget Assumptions:

(1) Construction cash flows reflect 45 percent ownership through December 2014 and are 

subsequently reduced in accordance with the projected ownership sale date. Total 

estimated project cost including transmission is $3,961.5 million at a reduced 

ownership interest of 35 percent. At 45 percent, the total estimated project cost is 

$5,047.6 million.

(2) Will be financed by internally generated funds, taxable and tax-exempt debt.
I-28

Purchase Commitments - The Authority has contracted for long-term coal purchases under contracts with 

estimated outstanding minimum obligations after December 31, 2013. The disclosure of minimum obligations 

(including market re-opener contracts) shown below is based on the Authority’s contract rates and represents 

management’s best estimate of future expenditures under long-term arrangements.

Years Ending December 31, 

With Re-openers 

(All Tons) (1)

Without Re-openers 

(Fixed Tons) (2)

 (Thousands)

2014 $ 278,155 $ 278,155 

2015 198,054 198,054 

2016 193,974 193,974 

2017 98,902 98,902 

2018 100,385 100,385 

2019 76,418 76,418 

 Total $ 945,888 $ 945,888 

(1) Includes tons which the Authority can elect not to receive.

(2) Includes tons which the Authority must receive.

The Authority has the following outstanding obligations under existing long-term purchased power contracts as of 

December 31, 2013:

Contracts with Minimum Fixed Payment Obligations

Number of Delivery Remaining Obligations

Contracts Beginning Term (Millions)

1 1985 21 Years $ 54.6 

1 2011 1 Year 9.9 

1 2012 2 Years 46.4 

1 2014 11 Years 0.0 (1)

(1) Contract obligation based on actual monthly purchase amount.

Contracts with Power Receipt and Payment Obligations (2)

Number of Delivery Remaining Obligations

Contracts Beginning Term (Millions)

1 2010 12 Years $ 233.1 

1 2013 20 Years 19.0 

2 2013 30 Years 673.9 

1 2013 20 Years 8.5 

1 2014 28 Years 456.6 

(2) Payment required upon receipt of power. Assumes no change in 

indices or escalation.
I-29

The Authority entered into agreements effective October 1, 2008, whereby New Horizon Electric Cooperative, Inc. 

assigned its interests, rights and obligations in contracts with Duke Energy Corporation and SCE&G for network 

integration transmission service to the Authority. The agreements are for network transmission service for the

Upstate Load as defined in Note 9 – Contracts with Electric Power Cooperatives. A payment schedule for these 

agreements shows that $8.4 million will be due in 2014, with remaining annual payments totaling $21.4 million 

through the end of the contract term in 2023. However, a majority of the Upstate Load will transition to a new 

supplier as stated in Note 9 and the Authority’s obligation for transmission service for this load will decrease in 

approximately the same proportion. At the end of the transition period, the Authority shall no longer be 

responsible for purchasing transmission service for the load served by the new supplier.

CSX Transportation, Inc. (CSX) provides substantially all rail transportation service for the Authority’s Cross and 

Winyah coal-fired generating stations. The Authority also interchanges with some short line railroads via CSX for 

the movement of coal. The CSX contract, effective beginning January 1, 2011, will continue to apply a price per 

ton of coal moved, along with a mileage based fuel surcharge and minimum tonnage obligation. 

The Authority has commitments for nuclear fuel, nuclear fuel conversion, enrichment and fabrication contracts for

V.C. Summer Units 1, 2 and 3. As of December 31, 2013, these contracts total approximately $490.4 million over 

the next 21 years. 

In 2010, the Authority amended the Rainey Generating Station Long-Term Parts and Long-Term Service Contract 

with General Electric International, Inc. (GEII). In lieu of exercising its option to terminate the Contract for 

convenience and to pursue non-OEM parts and services, the Authority negotiated an amendment with reduced 

pricing for maintenance and fixed escalation. The contract provides a contract performance manager (CPM), 

initial spare parts, parts and services for specified planned maintenance outages, remote monitoring and 

diagnostics of the turbine generators and combustion tuning for the gas turbines. 

The amended contract value is approximately $97.2 million, excluding escalation and adjustments for liquidated 

damages and bonuses. The contract term extends through the second major inspection for Rainey 1 (expected 

to be completed in 2018). Rainey 2A and 2B have reached the contract “performance end date.” The Authority’s 

estimated remaining commitment on the contract is $47.2 million and the Authority is currently exploring options 

for these units, including a potential extension of the GEII contract. The contract can be terminated for 

convenience at the end of 2015. The Authority’s Board has approved recovery of contract expenditures on a 

straight-line basis over the term of the contract.

Effective November 1, 2000, the Authority contracted with Transcontinental Gas Pipeline Corporation 

(TRANSCO) to supply gas transportation needs for its Rainey Generating Station. This is a firm transportation 

contract covering a maximum of 80,000 decatherms per day for 15 years.

Risk Management - The Authority is exposed to various risks of loss related to torts; theft of, damage to, and 

destruction of assets; business interruption; and errors and omissions. The Authority purchases commercial 

insurance to cover these risks, subject to coverage limits and various exclusions. Settled claims resulting from 

these risks did not exceed commercial insurance coverage in 2013. Policies are subject to deductibles ranging 

from $500 to $2.0 million, with the exception of named storm losses which carry deductibles from $2.0 million up 

to $5.0 million. Also a $1.4 million general liability self-insured layer exists between the Authority’s primary and 

excess liability policies. During 2013, there were minimal payments made for general liability claims.

The Authority is self-insured for auto, dental, worker’s compensation and environmental incidents that do not arise 

out of an insured event. The Authority purchases commercial insurance, subject to coverage limits and various 

exclusions, to cover automotive exposure in excess of $2.0 million per incident. Risk exposure for the dental plan

is limited by plan provisions. Estimated exposure for worker’s compensation is based on an annual actuarial 

study using loss and exposure information valued as of June 30, 2013. In addition, there have been no third-party 

claims regarding environmental damages for 2013 or 2012. 
I-30

Claim expenditures and liabilities are reported when it is probable that a loss has occurred and the amount of the 

loss can be reasonably estimated. The amount of the self-insurance liabilities for auto, dental, worker’s 

compensation and environmental remediation is based on the best estimate available. Changes in the reported 

liability were as follows:

Years Ended December 31, 2013 2012

(Thousands)

Unpaid claims and claim expense at beginning of year $ 1,778 $ 1,612 

Incurred claims and claim adjustment expenses:

Add: Provision for current year events 2,940 2,392 

Less: Payments for current and prior years 2,180 2,226 

Total unpaid claims and claim expenses at end of year $ 2,538 $ 1,778 

The Authority pays insurance premiums to certain other State agencies to cover risks that may occur in normal 

operations. The insurers promise to pay to, or on behalf of, the insured for covered economic losses sustained 

during the policy period in accordance with insurance policy and benefit program limits. The State assumes all 

risks for the following:

(1) claims of covered employees for health benefits covered through South Carolina Public Employee 

Benefit Authority (PEBA); not applicable for worker’s compensation injuries; and 

(2) claims of covered employees for basic long-term disability and group life insurance benefits (PEBA

and Retirement System).

Employees elect health coverage through the State’s self-insured plans. However, additional group life and longterm disability premiums are remitted to commercial carriers. The Authority assumes the risk for claims of 

employees for unemployment compensation benefits and pays claims through the State’s self-insured plan.

Nuclear Insurance - The maximum liability for public claims arising from any nuclear incident has been 

established at $13.6 billion by the Price-Anderson Indemnification Act. This $13.6 billion would be covered by 

nuclear liability insurance of $375.0 million per reactor unit, with potential retrospective assessments of up to 

$127.3 million per licensee for each nuclear incident occurring at any reactor in the United States (payable at a 

rate not to exceed $18.9 million per incident, per year). Based on its one-third interest in V.C. Summer Nuclear 

Unit 1, the Authority could be responsible for the maximum assessment of $42.4 million, not to exceed 

approximately $6.3 million per incident, per year. This amount is subject to further increases to reflect the effect

of (i) inflation, (ii) the licensing for operation of additional nuclear reactors and (iii) any increase in the amount of 

commercial liability insurance required to be maintained by the NRC.

Additionally, SCE&G and the Authority maintain, with Nuclear Electric Insurance Limited (NEIL), $500.0 million 

primary and $2.25 billion excess property and decontamination insurance to cover the costs of cleanup of the 

facility in the event of an accident. SCE&G and the Authority also maintain accidental outage insurance to cover 

replacement power costs (within policy limits) associated with an insured property loss. In addition to the 

premiums paid on these three policies, SCE&G and the Authority could also be assessed a retrospective 

premium, not to exceed ten times the annual premium of each policy, in the event of property damage to any 

nuclear generating facility covered by NEIL. Based on current annual premiums and the Authority’s one-third 

interest, the Authority’s maximum retrospective premium would be approximately $3.8 million for the primary 

policy, $4.0 million for the excess policy and $1.4 million for the accidental outage policy.

SCE&G and the Authority maintain builder’s risk insurance and marine cargo insurance for the V.C. Summer 

Units 2 and 3 construction. The builder’s risk policy provides coverage of $2.75 billion accidental nuclear property 

damage with a sub-limit of $500.0 million for accidental property damage that is caused by or results from any 

covered peril other than radioactive contamination resulting from nuclear reaction, nuclear radiation or the release 

of radioactive materials, with deductibles ranging from $250,000 to $5.0 million. This policy also carries a 

potential retrospective premium of approximately $42.0 million. Based on the Authority’s current 45 percent

ownership interest, the Authority’s maximum retrospective premium would be approximately $18.9 million. The 

marine cargo/transit policy provides coverage of $300.0 million, with deductibles ranging from $25,000 to 

$75,000.
I-31

The Authority is self-insured for any retrospective premium assessments, claims in excess of stated coverage or 

cost increases due to the purchase of replacement power associated with an uninsured event. Management does 

not expect any retrospective assessments, claims in excess of stated coverage or cost increases for any periods 

through December 31, 2013.

Clean Air Act - The Authority endeavors to ensure that its facilities comply with applicable environmental 

regulations and standards.

In addition to the existing Clean Air Act (CAA) Federal Acid Rain Program, the EPA has promulgated and is 

implementing the Clean Air Interstate Rule (CAIR) for SO2 and NOx emissions. 

The Cross State Air Pollution Rule (CSAPR) was EPA’s replacement for CAIR. However, the D.C. Circuit U.S. 

Court of Appeals overturned CSAPR on August 21, 2012, and instructed EPA to administer CAIR in the interim 

until EPA develops a replacement rule. CSAPR remains in the appeals process and is currently pending further 

review in the U.S. Supreme Court.

In place of the vacated federal Clean Air Mercury Rule (CAMR), South Carolina utilities and DHEC finalized a 

Memorandum of Agreement (MOA) in which the Authority committed to install and certify mercury Continuous 

Emissions Monitoring Systems (CEMS) at a set of agreed-upon coal-fired units and collaborate with the South 

Carolina utilities and DHEC to provide support for a state-wide assessment evaluating the mercury deposition 

resulting from coal-fired power plants in South Carolina. In 2009, the mercury CEMS were installed at the 

specified Authority units and utilities began initial reporting. There are no cap and trade or emissions limitations 

requirements per the MOA.

The Authority has been operating under a settlement agreement, called the Consent Decree, which became 

effective June 24, 2004. The settlement with EPA and DHEC was related to certain environmental issues 

associated with coal-fired units. It involved the payment of a civil penalty, an agreement to perform certain 

environmentally beneficial projects and capital costs to achieve emissions reductions over the period ending 

2013. Capital costs have been offset by a reduced need to purchase emission credits. All emissions reduction

projects required by the Consent Decree have been completed.

Currently, there are both legislative and regulatory efforts to reduce greenhouse gas emissions. The Authority 

continues to review proposed greenhouse gas regulations to assess potential impacts to its operations. In 2010, 

EPA finalized the Prevention of Significant Deterioration (PSD) Tailoring Rule for regulating greenhouse gases 

through the PSD permitting process under the existing CAA. EPA issued Best Available Control Technology 

(BACT) Guidance in 2010 for use under the rule effective July 1, 2011. The Authority will continue to monitor both 

regulatory and legislative efforts to reduce greenhouse gas emissions to assess potential impacts to its 

operations.

Through the maximum achievable control technology (MACT) regulatory process, the EPA has proposed the 

Utility MACT regulations to reduce the emissions of mercury and other hazardous air pollutants (HAPs) from coal 

and oil-fired electric utility steam boilers. As a part of EPA rule development, the Authority participated in the 

EPA’s mandatory Information Collection Request (ICR) for mercury and other HAPs for its coal-fired and oil-fired 

units. The ICR required facility and fuel information as well as stack testing at Cross, Winyah and Jefferies 

generating stations. 

The proposed MACT rule was released in March 2011 with a public notice comment period. The Authority

submitted comments to the proposed rule. The final MACT rule was pre-released by EPA December 16, 2011, as 

the Mercury and Air Toxics (MATS) rule. It was published in the Federal Register on February 16, 2012, and 

became effective on April 16, 2012, with a compliance deadline for existing units of April 16, 2015. 

The MATS rule includes emissions limitations for mercury, acid gases and other HAPs from existing and new 

coal-fired and oil-fired electric utility steam units. This is EPA’s first national standard to reduce mercury and 

other air toxics from coal-fired and oil-fired power plants. 
I-32

On July 20, 2012, EPA announced it is reconsidering certain technical aspects of the rule for new power plants. 

The Authority submitted comments to EPA by the January 7, 2013 deadline, and EPA completed the updated rule 

in March 2013. The compliance date for new power plants remained set for July 16, 2015. In June 2013, EPA 

reopened the public comment period on reconsideration of startup and shutdown provisions. The Authority 

submitted comments to EPA. EPA intends to complete this portion of reconsideration sometime in 2014. The 

compliance deadline for existing units remains April 16, 2015, with the potential for a state-approved one year 

extension.

Safe Drinking Water Act - The Authority continues to monitor regulatory issues impacting drinking water 

systems at the Authority’s regional water systems, generating stations, substations and other auxiliary facilities. 

DHEC has regulatory authority of potable water systems in South Carolina under The State Primary Drinking 

Water Regulation, R.61-58; the Authority endeavors to manage its potable water systems in compliance with 

R.61-58.

Clean Water Act - The Clean Water Act (CWA) prohibits the discharge of pollutants, including heat, from point 

sources into waters of the United States, except as authorized in the National Pollutant Discharge Elimination

System (NPDES) permit program. DHEC has been delegated NPDES permitting authority by the EPA and 

administers the NPDES permit program for the State.

Wastewater discharges from the generating stations and the regional water plants are governed by NPDES 

permits issued by DHEC. Further, the storm water from the generating stations must be managed in accordance 

with the State’s NPDES Industrial General Permit for storm water discharges. Storm water from construction 

activities must also be managed under the State’s NPDES General Permit for storm water discharges from 

construction activity. The Authority constantly strives to operate in compliance with these permits.

Further, EPA issued a proposed rule in June 2013 to amend the Steam Electric effluent guidelines and standards 

that would require additional control and treatment of wastewater discharges from the generating stations. The 

proposal, if enacted, is expected to require more control of heavy metals removed by air pollution control (ash and 

FGD sludge) and new internal outfalls that will likely require additional wastewater treatment systems to meet the 

new limitations.

The CWA, under Section 316(b), also requires that cooling water intake structures (CWIS) reflect the best 

technology available for minimizing adverse environmental impacts, such as the impingement of fish and shellfish 

on the intake structures and the entrainment of eggs and larvae through cooling water systems. The EPA is 

expected to publish the final rule under the CWA Section 316(b) in April 2014. Based on the proposed rule and 

subsequent publications from the EPA, changes to the intake structures may be required at Cross and Winyah 

generating stations. Grainger generating station will not be subject to the final regulation, and the Authority 

continues to evaluate the remaining CWIS.

The EPA also has regulations under the CWA relating to Spill Prevention Control and Counter-measures (SPCC). 

These regulations require that applicable facilities, which include generating stations, substations and auxiliary 

facilities, maintain SPCC plans to meet certain standards. The Authority continually works to be in compliance 

with these regulations.

DHEC promulgated a regulation effective June 2012 which requires permitting the withdrawal and use of surface 

water. Although existing withdrawers, including the Authority’s generating and regional water systems are

grandfathered into this regulation, the Authority was required to submit permit applications for these intakes. In 

2013, the Authority received 30 year permits for all generating stations. These surface water withdrawal permits 

require the facility to develop drought contingency plans within 180 days after the permit is issued. Permits are 

pending for Lake Marion and Lake Moultrie regional water systems.

 

Hazardous and Non-Hazardous Substances, Wastes and Byproducts - Section 311 of the CWA 

imposes substantial penalties for spills of Federal EPA-listed hazardous substances into water and for failure to 

report such spills. The Comprehensive Environmental Response, Compensation and Liability Act of 1980

(CERCLA) provides for the reporting requirements to cover the release of hazardous substances into the 

environment. Additionally, the EPA regulations under the Toxic Substances Control Act (TSCA) impose stringent 

requirements for labeling, handling, storing and disposing of polychlorinated biphenyls (PCBs) and associated 

equipment.
I-33

Under the CERCLA and Superfund Amendments and Reauthorization Act (SARA), the Authority could be held 

responsible for damages and remedial action at hazardous waste disposal facilities utilized by it, if such facilities 

become part of a Superfund effort. Moreover, under SARA, the Authority must comply with a program of 

emergency planning and a “Community Right-To-Know” program designed to inform the public about more 

routine chemical hazards present at the facilities. Both programs have stringent enforcement provisions. The 

Authority endeavors to comply with the applicable provisions of TSCA, CERCLA and SARA, but it is not possible 

to determine if some liability may be imposed in the future for past waste disposal or compliance with new 

regulatory requirements. The Authority strives to comply with all aspects of Resource Conservation and 

Recovery Act (RCRA) regarding appropriate disposal of chemical wastes. 

The Authority generates coal combustion residuals (CCRs) at the coal fired generating stations. The vast majority 

of the CCRs are fly ash, bottom ash, gypsum and scrubber sludge. The CCRs are either beneficially used or 

disposed of. The CCRs are exempt from hazardous waste regulation under the RCRA. However, EPA has 

proposed certain alternative revisions to the RCRA, that if adopted as a final rule, would add significant cost to the 

disposal and handling of CCRs and possibly restrict beneficial use. The EPA has entered into a Consent Decree 

which requires it to take final action regarding the proposed alternative revisions to the RCRA by December 19, 

2014.

The Solid Waste Disposal Act and Energy Policy Act gives EPA authority to regulate Underground Storage Tanks 

(USTs). EPA regulations concerning USTs are contained in 40 CFR Parts 280-282. DHEC has granted state 

program approval in 2002 and regulates USTs under R. 61-92, Part 280 dated 2008. This regulation provides 

requirements for the design, installation, operation, closure, release detection, reporting and corrective action and 

financial responsibility. The Authority’s corporate policy number 2-11-02 provides guidance for the proper 

management and monitoring of USTs for environmental and regulatory compliance.

Pollution Remediation Obligations – The Authority follows GASB 49 which addresses standards for 

pollution (including contamination) remediation obligations for activities such as site assessments and cleanups. 

GASB 49 does not include standards for pollution remediation obligations that are addressed elsewhere. 

Examples of obligations addressed in other standards include pollution prevention and control obligations for 

remediation activities required upon the retirement of an asset, such as ash pond closure and post-closure care 

and nuclear power plant decommissioning.

The Authority had recorded $15,000 for pollution remediation liabilities for each of the years ended December 31, 

2013 and 2012. The method used to estimate the liabilities consists of weighting a range of possible estimated 

job cost amounts and calculating a weighted average cost. The weights and estimated costs are developed using 

professional engineering judgment acquired through years of estimating and completing many pollution 

remediation projects. 

Homeland Security – The Department of Homeland Security (DHS) was established by the Homeland Security 

Act of 2002, a portion of which relates to anti-terrorism standards at facilities which store or process chemicals. 

The Authority has been proactive in conducting security assessments at its facilities and will continue to strive to 

comply with these evolving regulations. 

Legal Matters – The Authority has paid approximately $221.6 million, including interest, in settlement of a 

lawsuit brought by a number of landowners located along the Santee River primarily in Williamsburg and 

Georgetown Counties, South Carolina. The plaintiffs claimed damage to their real estate as a result of flooding 

that has occurred since the U.S. Army Corps of Engineers’ (Corps) Cooper River Rediversion Project was 

completed in 1985. The Authority has also paid an additional $10.4 million in costs and attorney fees to the 

plaintiffs. The Authority submitted a claim seeking indemnification from the Corps on August 30, 2011. The Corps 

declined to pay the claim and the Authority appealed matter to the Armed Services Board of Contract Appeals 

(ASBCA). The ASBCA previously had determined that the contract between the Corps and the Authority required 

the Corps to indemnify the Authority for certain claims arising out of the construction and operation of the project. 

On February 14, 2013, the ASBCA ruled that the Authority is entitled to indemnification from the Corps in the 

amount of $234.9 million for costs incurred as a result of the Santee River Litigation. In addition, the ASBCA 

ruled that the Authority is entitled to interest on the costs pursuant to the Contract Disputes Act, calculated from 

August 20, 2001 until paid. The Corps has appealed this decision to the United States Court of Appeals for the 

Federal Circuit. Briefing on the appeal will be complete in the first quarter of 2014 and the Authority expects that 

the Court of Appeals will render a decision on the appeal in 2014.
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In June 2012, several environmental advocacy groups filed suit against the Authority in the Court of Common 

Pleas in Horry County seeking injunctive relief with regard to closure of ash ponds at the Grainger Generating 

Station. The suit did not seek damages but alleged that an unlawful discharge of arsenic and other contaminants 

had occurred and requested that the court order the removal and offsite storage of all ash contained in the ponds. 

In April 2013, an environmental advocacy group filed suit against the Authority alleging that violations of the 

federal Clean Water Act had occurred at Grainger Generating Station. The suit did not seek damages but made 

claims for injunctive relief, civil penalties and costs and attorneys’ fees. The Authority settled both suits in 

November 2013. The settlement did not require the Authority to make any payment to the litigants. The Authority 

intends to properly close the ash ponds by excavation and beneficial use of the ash in accordance with regulatory 

requirements.

In May 2013, Horry Cooperative, a member of Central, sued the Authority seeking indemnification for claims in a 

class action lawsuit brought against Horry Cooperative by certain of its customers. The customers allege mold 

damage to their homes was caused by vapor barriers installed in accordance with the Authority’s energy 

efficiency recommendations. Horry Cooperative’s complaint alleges the Authority knew the vapor barrier could 

cause moisture problems but failed to disclose the information to Horry Cooperative and failed to advise Horry 

Cooperative that the vapor barrier should be a recommendation rather than a requirement. The Authority does 

not yet know the number of customers or the amount of claims involved. The Authority intends to vigorously 

defend the lawsuit but cannot predict the outcome.

NOTE 11 – RETIREMENT PLAN:

Substantially all Authority regular employees must participate in one of the components of the South Carolina 

Retirement System (SCRS), a cost sharing, multiple-employer public employee retirement system, which was 

established by Section 9-1-20 of the South Carolina Code of Laws. 

The payroll for active employees covered by the SCRS was as follows:

Years Ended December 31, 2013 2012 2011

(Millions) 

Payroll for Active Employees $ 126.9 $ 125.7 $ 124.4 

Vested employees (Class Two Members) who retire at age 65 or with 28 years of service at any age are entitled 

to a retirement benefit, payable monthly for life. Vested employees (Class Three Members) who retire at age 65 

or meet the “rule of 90 requirement” (i.e., the total of the member’s age and the member’s creditable service 

equals at least 90 years), are entitled to a retirement benefit, payable monthly for life. The annual benefit amount 

is equal to 1.82 percent of their average final compensation times years of service. Benefits fully vest on reaching 

five years of service for Class Two Members and eight years for Class Three Members. Reduced retirement 

benefits are payable as early as age 60 with vested service or 55 with 25 years of service for Class Two 

Members. The SCRS also provides death and disability benefits. Benefits are established by State statute.

Effective January 1, 2001, Section 9-1-2210 of the South Carolina Code of Laws allowed SCRS employees 

eligible for service retirement to participate in the Teacher and Employee Retention Incentive (TERI) Program. 

TERI participants may retire and begin accumulating retirement benefits on a deferred basis without terminating 

employment for up to five years. Upon termination of employment or at the end of the TERI period, whichever is 

earlier, participants will begin receiving monthly service retirement benefits which include any cost of living 

adjustments granted during the TERI period. Because participants are considered retired during the TERI period, 

they do not earn service credit or disability retirement benefits. Effective July 1, 2005, TERI employees began “recontributing” to the SCRS at the prevailing rate. However, no service credit is earned under the new regulations. 

The group life insurance of one times annual salary was re-established for TERI participants. 
I-35

Effective July 1, 2012, the TERI program will close for Class Two members (members with effective date prior to 

July 1, 2012) on June 30, 2018, and it is not available to Class Three members (members with effective date on 

or after July 1, 2012). TERI will be phased out in a 5-4-3-2-1 format. Members who enter the TERI program after 

July 1, 2013, will not be eligible to participate for the full five years. TERI participation will end on June 30, 2018, 

regardless of when a member enters the program.

Article X, Section 16 of the South Carolina Constitution requires that all State-operated retirement plans be 

funded on a sound actuarial basis. Title 9 of the South Carolina Code of Laws (as amended) prescribes 

requirements relating to membership, benefits and employee/employer contributions.

All employees are required by State statute to contribute to the SCRS at the prevailing rate (currently 7.50

percent). The Authority contributed 10.45 percent of the total payroll for SCRS retirement. For 2013, the Authority 

also contributed an additional 0.15 percent of total payroll for group life. The contribution requirements for the 

prior three years were as follows:

Years Ended December 31, 2013 2012 2011

(Millions) 

From the Authority $ 13.3 $ 12.5 $ 11.7 

From Employees 9.2 8.5 8.1 

The Authority made 100 percent of the required contributions for each of the three years.

The SCRS issues a stand-alone financial report that includes all required supplementary information. The report 

may be obtained by writing to: South Carolina Retirement System, P.O. Box 11960, Columbia, S.C. 29211.

Effective July 1, 2002, new employees have a choice of type of retirement plan in which to enroll. The State 

Optional Retirement Plan (State ORP) which is a defined contribution plan is an alternative to the SCRS

retirement plan which is a defined benefit plan. The contribution amounts are the same, (7.50 percent employee 

cost and 10.45 percent employer cost); however, 5.00 percent of the employer amount is directed to the vendor 

chosen by the employee and the remaining 5.45 percent is to the Retirement System. As of December 31, 2013, 

the Authority had 36 employees participating in the State ORP and consequently the related payments are not 

material.

The Authority also provides retirement benefits to certain employees designated by management and the Board 

under supplemental executive retirement plans (SERP). Benefits are established and may be amended by 

management and the Authority’s Board and includes retirement benefit payments for a specified number of years 

and death benefits. The cost of these benefits is actuarially determined annually. Beginning in 2006, these plans 

were segregated into internal and external funds. The qualified benefits are funded externally with the annual 

cost set aside in a trust administered by a third party. The pre-2006 retiree benefits and the non-qualified benefits 

are funded internally with the annual cost set aside and managed by the Authority. A summary of the Authority’s 

SERP activity is as follows:

Years Ended December 31, 2013 2012

(Millions) 

Total cost $ 1.1 $ 1.2 

Accrued liability 5.3 5.4 
I-36

V.C. Summer Retirement - The Authority and SCE&G are parties to a joint ownership agreement at the V.C. 

Summer Nuclear Station. As such, the Authority is responsible for funding its share of pension requirements for 

the nuclear station personnel. Any earnings generated from the established pension plan are shared 

proportionately and used to reduce the allocated funding. 

As of December 31, 2013 and 2012, the Authority had over-funded its share of requirements by $910,000 and 

$3.4 million, respectively. This receivable however, is offset by a regulatory liability as required by FASB ASC 

715. The balances were approximately $15.0 million and $30.2 million for the unfunded portion of pension 

benefits at December 31, 2013 and 2012, respectively. Additional information may be obtained by reference to 

the SCANA Corporation Annual Report on Form 10K as filed with the Securities Exchange Commission as of 

December 31, 2013.

NOTE 12 – OTHER POSTEMPLOYMENT BENEFITS (OPEB):

Vacation / Sick Leave – Full-time employees earn 10 days of vacation leave for service under five years and 

15 days of vacation leave for service under 11 years. Employees earn an additional day of vacation leave for 

each year of service over 10 until they reach the maximum of 25 days per year. Employees earn two hours per 

pay period, plus 20 additional hours at year-end for sick leave.

Employees may accumulate up to 45 days of vacation leave and 180 days of sick leave. Upon termination, the 

Authority pays employees for unused vacation leave at the pay rate then in effect. In addition, the Authority pays 

employees upon retirement 20 percent of their sick leave at the pay rate then in effect.

Plan Description - The Authority participates in an agent multiple-employer defined benefit healthcare plan 

whereby PEBA provides certain health, dental and life insurance benefits for eligible retired employees of the 

Authority. The retirement benefits available are defined by PEBA and substantially all of the Authority’s 

employees may become eligible for these benefits if they retire at any age with a minimum of 10 years of earned 

service or at age 60 with at least 20 years of service. Currently, approximately 734 retirees meet these 

requirements. 

For employees hired May 2, 2008 or thereafter, the number of years of earned service necessary to qualify for 

funded retiree insurance is 15 years for a one-half contribution, and 25 years for a full contribution. PEBA may be 

contacted at: Retirement Benefits, PO Box 11660, Columbia, S.C. 29211-1960.

Funding Policy - Prior to 2010, the Authority used the unfunded pay-as-you-go option (or cash disbursement) 

method pursuant to GASB 45 to record the net OPEB obligations. During 2010, the Authority elected to adopt an 

advanced or pre-funding policy and established an irrevocable trust with Synovus Trust Company. This method 

of funding will eventually result in lower contributions over time compared to the prior pay-as-you-go funding 

policy.
I-37

Annual OPEB Cost - The Authority’s annual OPEB cost is calculated based on the annual required 

contribution of the employer (ARC), an amount actuarially determined in accordance with the parameters of 

GASB 45. The ARC represents a level of funding that is projected (if paid on an on-going basis) to recognize the 

normal cost each year and to amortize any unfunded actuarial liabilities (or funding excess) over a period not to 

exceed 30 years. The Authority’s contribution towards ARC is equal to the actual disbursements during the year 

for health care benefits for retired employees plus annual funding amounts for the trust. The Authority’s annual 

OPEB cost (expense) for the current year was as follows:

Year Ended December 31, 2013 2012

(Thousands)

Annual required contribution $ 11,687 $ 10,172 

Interest on OPEB obligation 513 652 

Adjustment to ARC (442) (563)

 Annual OPEB cost 11,758 10,261 

Net estimated employer contributions (11,302) (12,795)

 Increase (decrease) in net OPEB obligation $ 456 $ (2,534)

Net OPEB Obligation - beginning of year $ 9,325 $ 11,859 

Net OPEB Obligation - end of year $ 9,781 $ 9,325 

The Authority’s annual OPEB cost, the percentage of annual OPEB cost contributed to the plan, and the net 

OPEB obligation for fiscal year ending December 31, 2013 and the preceding two fiscal years were as follows:

Annual OPEB 

Cost

Employer 

Amount 

Contributed

Net OPEB 

Obligation

Percentage 

Contributed

Years Ended December 31, (Thousands) (%)

2011 $ 9,841 $ 12,396 $ 11,859 126.0

2012 10,261 12,795 9,325 124.7

2013 11,758 11,302 9,781 96.1

Funded Status and Funding Progress - The funded status of the Authority’s retiree health care plan under 

GASB 45 as of December 31, 2012, the latest actuarial study date, is as follows:

Required Supplementary Information - Schedule of Funding Progress

Actuarial Value 

of Assets (a)

Actuarial 

Accrued Liability 

(AAL) (b)

Annual Covered 

Payroll (c)

Unfunded AAL 

(UAAL) (b) - (a)

Funded Ratio 

(a / b)

Ratios of UAAL 

to Annual 

Covered 

Payroll (b-a)/(c)

(Thousands) (%)

$ 27,829 $ 170,040 $ 113,683 $ 142,211 16.4 125.1

Note: As of December 31, 2013, the OPEB trust had assets of $32.9 million. 

The required schedule of funding progress presented as required supplementary information provided multi-year 

trend information that shows whether the actuarial value of plan assets is increasing over time relative to the 

actuarial accrued liability for benefits.
I-38

Actuarial Methods and Assumptions - The Projected Unit Credit actuarial cost method is used to calculate 

the GASB ARC for the Authority’s retiree health care plan. Using the plan benefits, the present health premiums 

and a set of actuarial assumptions, the anticipated future payments are projected. The projected unit credit 

method then provides for a systematic recognition of the cost of these anticipated payments. The yearly ARC is 

computed to cover the cost of benefits being earned by covered members, as well as to amortize a portion of the 

unfunded accrued liability.

Actuarial valuations involve estimates of the value of reported amounts and assumptions about the probability of 

events in the future. Amounts determined regarding the funded status and the annual required contributions of 

the Authority’s retiree health care plan are subject to continual revision as actual results are compared to past 

expectations and new estimates are made about the future. 

Projections of health benefits are based on the plan as understood by the Authority and include the types of 

benefits in force at the valuation date and the pattern of sharing benefit costs between the Authority and its 

employees to that point. Actuarial calculations reflect a long-term perspective and employ methods and 

assumptions that are designed to reduce short-term volatility in actuarial accrued liabilities and the actuarial value 

of assets. Significant methods and assumptions were as follows:

Actuarial Methods and Assumptions

Inflation rate 3.00% per annum

Investment rate of return 5.50% net of expenses

Actuarial cost method Projected Unit Credit Cost Method

Amortization method Level as a percentage of employee payroll

Amortization period 30 year, open amortization

Payroll growth 3.00% per annum

Medical trend: 

 Initial 7.00%

 Ultimate 4.50% after 10 years

Drug trend:

 Initial 7.25%

 Ultimate 4.50% after 10 years

V.C. Summer OPEB - The Authority is responsible for funding its share of OPEB costs for nuclear station 

employees. The Authority’s liability balances as of December 31, 2013 and 2012 were approximately $10.1

million and $9.5 million, respectively.

In accordance with FASB ASC 715, the Authority had recorded a regulatory asset and liability of approximately 

$2.6 million and $5.3 million for the unfunded portion of OPEB costs at December 31, 2013 and 2012, 

respectively. Additional information may be obtained by reference to the SCANA Corporation Annual Report on 

Form 10K as filed with the Securities Exchange Commission as of December 31, 2013.

NOTE 13 - CREDIT RISK AND MAJOR CUSTOMERS:

In 2013, the Authority had one customer that accounted for more than 10 percent of the Authority’s sales:

Customer: 2013 2012

(Millions)

Central $ 1,038 $ 1,115 

The Authority maintains an allowance for uncollectible accounts based upon the expected collectability of all 

accounts receivable. The allowance at each year ended December 31, 2013 and 2012 was $1.3 million.
I-39

NOTE 14 – SUBSEQUENT EVENT(S):

In conjunction with the preparation of these financial statements the Authority has evaluated subsequent events 

through February 21, 2014, the date the financial statements were available for issuance, and had the following to 

report:

 On January 27, 2014, the Authority’s Board of Directors approved the sale of five percent of its ownership in 

V.C. Summer Units 2 and 3 to South Carolina Electric & Gas (SCE&G). Under the terms of the new 

agreement, SCE&G will own 60 percent of the new nuclear units and the Authority, 40 percent. Under the 

existing ownership agreement, SCE&G owns 55 percent and the Authority owns 45 percent. The five percent 

ownership interest would be acquired in three stages:

(1) one percent at the commercial operation date of the first new nuclear unit, anticipated to be in the 

second quarter of 2018;

(2) two percent no later than the first anniversary of such commercial operation date; and

(3) two percent no later than the second anniversary date of such commercial operation date.

 

The Agreement also provides that the Authority will not transfer any of its remaining ownership interest in the 

two new units until after the commercial operating date for both units.
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II-1 

Appendix II 

SUMMARY OF CERTAIN PROVISIONS OF THE REVENUE OBLIGATION RESOLUTION 

 The following statements are summaries of certain provisions of the Revenue Obligation Resolution. 

Except as otherwise provided in this Official Statement, terms used under this caption which are defined in the 

Revenue Obligation Resolution, including, but not limited to those defined hereinafter, are used herein as so 

defined. Certain other provisions of the Revenue Obligation Resolution are summarized under the caption 

“SECURITY FOR THE 2014M1 BONDS.”

Definitions of Certain Terms Used in Revenue Obligation Resolution

 The following words and phrases are defined in the Revenue Obligation Resolution as hereinafter set 

forth. 

 “Capital Costs” shall mean the Authority's costs of (i) physical construction of or acquisition of real or 

personal property or interests therein for any project, together with incidental costs (including legal, 

administrative, engineering, consulting and technical services, insurance and financing costs), working capital and 

reserves deemed necessary or desirable by the Authority (including but not limited to costs of supplies, fuel, fuel 

assemblies and components or interests therein), and other costs properly attributable thereto; (ii) all capital 

improvements or additions, including but not limited to, renewals or replacements of or repairs, additions, 

improvements, modifications or betterments to or for any project; (iii) the acquisition of any other property 

(tangible or intangible), capital improvements or additions, or interests therein, deemed necessary or desirable by 

the Authority for the conduct of its business; (iv) any other purpose for which bonds, notes or other obligations of 

the Authority may be issued under the Enabling Act or under other applicable State statutory provisions (whether 

or not also classifiable as an operating expense); and (v) the payment of principal, interest, and redemption, tender 

or purchase price of (a) any Obligations, Commercial Paper or other indebtedness issued by the Authority for the 

payment of any of the costs specified above, including capitalized interest on such indebtedness, or (b) any 

indebtedness issued by the Authority to refund any indebtedness described in the preceding clause (a). 

 “Government Obligations” shall mean direct obligations of, or obligations the principal of and interest on 

which are unconditionally guaranteed by, the United States of America. 

 “Investment Securities” shall mean any of the following which at the time are legal investments under 

the laws of the State of South Carolina for the moneys held hereunder then proposed to be invested therein: (1) 

Government Obligations; (2) certificates which evidence ownership of the rights to payment of the principal of or 

interest on Government Obligations; (3) bonds, debentures, notes or participation certificates issued by the Bank 

for Cooperatives, the Federal Intermediate Credit Bank, the Federal Home Loan Bank System, the Export-Import 

Bank of the United States, Federal Land Bank, the Federal National Mortgage Association, the Tennessee Valley 

Authority, or any other agency or corporation which is or may hereafter be created by or pursuant to an Act of 

Congress of the United States as an agency or instrumentality thereof; (4) obligations of state and local 

government municipal bond issuers, provision for the payment of the principal of and interest on which shall 

have been made by deposit with a trustee or escrow agent of non-callable obligations described in (1), (2), or (3) 

of this subparagraph, the maturing principal of and interest on which when due and payable, shall provide 

sufficient funds to pay the principal of and interest on such obligations of state and local government municipal 

bond issuers (5) Public Housing Bonds, or Project Notes, fully secured by contracts with the United States; (6) 

repurchase agreements with banks that are members of the federal reserve system or with government bond 

dealers recognized as primary dealers by the Federal Reserve Bank of New York that are secured by securities 

described in (1) and (3) above having a current market value at least equal to one hundred two per cent (102%) of 

the amount of the repurchase agreement; (7) obligations of the State of South Carolina, (8) obligations of other 

states and investment contracts which obligations or investment contracts are rated at the time of purchase by each 

rating agency then maintaining a rating on the Obligations at the request of the Authority (each, a “Rating 

Agency”) in one of the three highest rating categories (as determined without regard to any refinement or 

graduation of such rating by a numerical modifier or otherwise, a “Rating Category”) of such Rating Agency; (9) 

deposits in interest bearing deposits or certificates of deposit or similar arrangements issued by any bank or 

national banking association (including the Trustee), which deposits, to the extent not insured by the Federal 
II-2 

Deposit Insurance Corporation, shall be secured by obligations described in clauses (2), (3), (4) or (7) of this 

paragraph, having a current market value (exclusive of accrued interest) at least equal to one hundred five percent 

(105%) of the amount of such deposits, which obligations described in clauses (2), (3), (4) or (7) of this paragraph 

shall have been deposited in trust by such bank or national association with the trust department of the Trustee or 

with a federal reserve bank or branch or, with the written approval of the Authority and the Trustee, with another 

bank, trust company or national banking association for the benefit of the Authority and the appropriate fund or 

account as collateral security for such deposits; (10) corporate securities, including commercial paper and fixed 

income obligations, which are, at the time of purchase, rated by a Rating Agency in one of its three highest Rating 

Categories for comparable types of obligations; and (11) such other investments from time to time allowed under 

applicable law. 

 “Obligations” shall mean any obligations, issued in any form of debt, authorized by a supplemental 

resolution, including but not limited to bonds, notes, bond anticipation notes, and Qualified Swaps, which are 

delivered under the Revenue Obligation Resolution. 

 “Operation and Maintenance Expenses” shall mean the Authority's expenses of operating the System, 

including, but not limited to, all costs of purchased power, operation, maintenance, generation, production, 

transmission, distribution, repairs, replacements, engineering, transportation, administration and general, audit, 

legal, financial, pension, retirement, health, hospitalization, insurance, taxes and any other expenses actually paid 

or accrued, of the Authority applicable to the System, as recorded on its books pursuant to generally accepted 

accounting principles, subject to the limitations with respect to take or pay contracts as set forth under “Take or 

Pay Contracts.” Operation and Maintenance Expenses shall not include (1) any costs or expenses for new 

construction, (2) charges for depreciation, (3) voluntary payments in lieu of taxes or (4) any taxes or tax payments 

now or hereafter required to be made to the State or any political subdivisions only out of surplus revenues, for 

example, payments required by Code Sections 58-31-90, 58-31-100 (2) and (3), and 58-31-110, Code of Laws of 

South Carolina 1976. 

 “Permitted Investments” shall mean the obligations referred to in (1), (2), (3) and (4) of the definition of 

the term "Investment Securities". 

 “Qualified Swap” shall mean, to the extent from time to time permitted by law, with respect to 

Obligations, any financial arrangement (i) which is entered into by the Authority with an entity that is a Qualified 

Swap Provider at the time the arrangement is entered into, (ii) which is a cap, floor or collar; forward rate; future 

rate; swap (such swap may be based on an amount equal either to the principal amount of such Obligations of the 

Authority as may be designated or a notional principal amount relating to all or a portion of the principal amount 

of such Obligations); asset, index, price or market-linked transaction or agreement; other exchange or rate 

protection transaction agreement; other similar transaction (however designated); or any combination thereof; or 

any option with respect thereto, executed by the Authority for the purpose of moderating interest rate fluctuations 

or otherwise, and (iii) which has been designated in writing to the Trustee by the Authority as a Qualified Swap 

with respect to such Obligations. 

 “Qualified Swap Provider” shall mean an entity whose senior long term obligations, other senior 

unsecured long term obligations or claims paying ability, or whose payment obligations under an interest rate 

exchange agreement are guaranteed by an entity whose senior long term debt obligations, other senior unsecured 

long term obligations or claims paying ability, are rated either (i) at least as high as the third highest Rating 

Category of each Rating Agency, but in no event lower than any Rating Category designated by each such Rating 

Agency for the Obligations subject to such Qualified Swap, or (ii) any such lower rating categories which each 

such Rating Agency indicates in writing to the Authority and the Trustee will not, by itself, result in a reduction or 

withdrawal of its rating on the Outstanding Obligations subject to such Qualified Swap that is in effect prior to 

entering into such Qualified Swap. 

 “Revenues” shall mean all the revenues, income, profits, tolls, rents, charges and returns of the Authority 

derived from its ownership or operation of the System, including the proceeds of any insurance covering business 

interruption loss relating to the System, but excluding other insurance proceeds and customer deposits. 
II-3 

System

 The Authority's System, as defined in the Revenue Obligation Resolution, consists generally of (a) 

facilities for the purpose of acquiring, controlling, storing, preserving, treating, distributing and selling water for 

(i) navigation, power, irrigation, reclamation, or sale to residential, commercial, agricultural or industrial 

customers or other governmental entities; and (b) plants, works, structures, facilities and equipment for the 

generation, manufacture, transmission or distribution of water power and electric power and energy, and of any 

other forms of power and energy when authorized by the Enabling Act. The System shall not include separate 

projects established by the Authority for any corporate purpose of the Authority other than those projects and 

purposes described hereinabove, nor separate systems described under “Separate Systems.” 

Revenue Fund

 The Revenue Obligation Resolution continues, for so long as any of the Revenue Obligations are 

Outstanding, the Revenue Fund. The Revenue Fund shall be held in trust and administered by the Authority. The 

Authority covenants and agrees in the Revenue Obligation Resolution to pay into the Revenue Fund, as promptly 

as practical after the receipt thereof, all Revenues. 

Funds and Accounts

 For the purpose of providing for the payment of the principal of, premium, if any, and interest on the 

Revenue Obligations, the Revenue Obligation Resolution creates a Revenue Obligation Fund. Payments into the 

Revenue Obligation Fund shall be made prior to the payments required to be made from, or retained in, the 

Revenue Fund to cover the cost of operation and maintenance of the System and the payments required to be 

made into the Lease Fund and the Capital Improvement Fund. 

Order of Payments From Revenue Fund 

 Under the Revenue Obligation Resolution, moneys shall be disbursed by the Authority from the Revenue 

Fund in the following order: 

 1. Revenue Obligation Fund: To pay when due to the Trustee the Revenue Obligation Fund 

Payments. 

 2. Operating and Maintenance: To pay expense of operation and maintenance. 

 3. Lease Fund: To pay when due into the Lease Fund an amount equal to the next due lease 

payments. 

 4. Capital Improvement Fund: To pay during each Fiscal Year into the Capital Improvement 

Fund amounts at least equal to the Minimum Capital Improvement Requirement. 

Any moneys remaining in the Revenue Fund each month after making the payments referenced above 

may be used by the Authority for any corporate purpose of the Authority. 

Certain Moneys Not Required to be Deposited in Revenue Fund

 The Revenue Obligation Resolution does not require the deposit into the Revenue Fund of any of the 

revenues, income, receipts, profits or other moneys of the Authority derived by the Authority through the 

ownership or operation of any separate system described under the section “Separate System” or through the 

ownership or operation of any separate project referred to under the section “System”. 
II-4 

Authorization of Revenue Obligations 

At any time one or more series of Revenue Obligations may be issued pursuant to the Revenue 

Obligation Resolution, upon the terms set forth in a Series Resolution, for any corporate purpose of the Authority, 

including the refunding or purchase of Revenue Obligations, provided there is no default under the Revenue 

Obligation Resolution. 

Separate Systems 

The System shall not include (i) any facilities for the purpose of providing water for sale to residential, 

commercial, agricultural or industrial customers or other governmental entities, or (ii) any facilities for the 

generation of any form of power and energy, or for the transmission and distribution of any form of power and 

energy, and any incidental properties constructed, acquired or leased in connection therewith, constructed or 

acquired by the Authority as a separate system, and if constructed or acquired with the proceeds of sale of bonds 

or other evidences of indebtedness, which bonds or other evidences of indebtedness are payable solely from the 

revenues or other income derived from the ownership or operation of such separate utility system, and may be 

further secured by a pledge of Revenues junior and subordinate to the pledge securing the Revenue Obligations 

and payable therefrom, but only after the revenues and other income derived from the ownership or operation of 

such separate utility system and pledged to the payment of such bonds or other indebtedness are so applied in 

accordance with the proceedings providing for the issuance of such bonds or other indebtedness. 

Junior Lien Obligations 

Nothing in the Revenue Obligation Resolution shall prevent the Authority from issuing bonds, notes, 

bond anticipation notes, warrants, certificates or other obligations or evidences of indebtedness the payment of 

which shall be made from the proceeds of Revenue Obligations or other indebtedness of the Authority or from 

Revenues, and if payable from Revenues shall be made junior and subordinate to the payment of the Revenue 

Obligations. The Authority may create special funds to provide for the payment of such obligations, payments to 

which shall be made after payments to the Revenue Obligation Fund, and may, if the Authority so provides, but 

need not be, junior to the payments into the Lease Fund. 

Insurance 

The Revenue Obligation Resolution requires the Authority to insure such of its various properties as are 

usually insured by utilities owning like properties in similar amounts and coverages, with insurance companies, 

and to carry liability insurance in reasonable amounts. 

Sale, Lease or Other Disposition of Properties 

 Subject to the next sentence, the Authority may sell, lease, or otherwise dispose of any part of its 

properties on such terms and conditions as may be prescribed by its Board of Directors. The Authority shall not 

take any action described in the preceding sentence unless, in the judgment of the Authority's Board of Directors, 

such action is desirable in the conduct of the Authority's business and does not materially impair the Authority's 

ability to comply with the rate covenant provisions of the Revenue Obligation Resolution. 

Take or Pay Contracts 

The Revenue Obligation Resolution does not prohibit the Authority from entering into take or pay 

contracts, including take or pay contracts with a separate system described under section “Separate Systems,” to 

purchase power under conditions whereby payments the Authority is required to make may be calculated, in 

whole or in part, on the basis of power which the Authority does not purchase, require or obtain for whatever 

reasons. However, payments made by the Authority under such a take or pay contract for power not available for 

any reason other than an emergency or forced outage lasting not more than one year or normal and regularly 

scheduled maintenance outage may not be treated as Operation and Maintenance Expenses. 
II-5 

Capital Improvement Fund 

The Revenue Obligation Resolution requires the deposit annually into the Capital Improvement Fund of 

an amount at least equal to the Minimum Capital Improvement Requirement defined as follows: an amount, 

which, together with the amounts deposited in the Capital Improvement Fund in the two immediately preceding 

Fiscal Years, will be at least equal to 8% of the revenues required by the Revenue Obligation Resolution to be 

paid into the Revenue Fund in the three immediately preceding Fiscal Years. Certain payments not made into the 

Capital Improvement Fund may be considered as a payment towards fulfillment of the Minimum Capital 

Improvement Requirement. 

 The moneys on deposit in the Capital Improvement Fund shall be used solely to pay Capital Costs. 

Lease Fund 

The Authority covenants that there will be paid monthly into the Lease Fund the amounts necessary to 

make payments under leases of properties or facilities leased to the Authority and used for the purpose of 

generating, transmitting and distributing all forms of power and energy. 

Events of Default and Remedies Under the Revenue Obligation Resolution 

A happening of one or more of the following constitutes an Event of Default under the Revenue 

Obligation Resolution: 

 (a) default in the due and punctual payment of any interest on any Revenue Obligation which 

shall continue for a period of 30 days; or 

 (b) default in the due and punctual payment of the principal of any Revenue Obligation, whether 

at the stated maturity thereof, at the mandatory redemption date, at the redemption date or upon 

declaration; or 

 (c) the Authority shall violate or fail to perform any of its covenants or agreements contained in 

the Revenue Obligation Resolution for 90 days after written notice of default is given to it by the 

Bond Fund Trustee or by the holder of any Revenue Obligation; or 

 (d) a default shall have occurred in respect of any bond, debenture, note or other evidence of 

indebtedness of the Authority, or in respect of any obligations of the Authority under any financing 

lease, whether now outstanding or existing or issued or otherwise undertaken hereafter, or under any 

indenture, resolution, lease or other agreement or instrument under which any such bond, debenture, 

note or other evidence of indebtedness or any such lease obligation has been or may be issued or by 

which any of the foregoing is or may be governed or evidenced, which default shall have resulted in 

the principal amount of such bond, debenture, note or other evidence of indebtedness or lease 

obligation becoming due and payable prior to its stated maturity or which default shall have been a 

default in the payment of principal when due and payable; or 

 (e) a decree or order by a court having jurisdiction in the premises shall have been entered 

judging the Authority as bankrupt or insolvent, or approving as properly filed a petition seeking 

reorganization or arrangement of the Authority under the Federal bankruptcy laws or any similar 

applicable Federal or South Carolina law, and such decree or order shall have continued 

undischarged or unstayed for a period of forty (40) days; or a decree or order of a court having 

jurisdiction in the premises for the appointment of a receiver or liquidator or trustee or assignee in 

bankruptcy or insolvency of the Authority or any of its property, or for the winding-up or liquidation 

of the Authority or any of its property, shall have been undischarged and unstayed for a period of 

sixty (60) days; or 

 (f) the Authority shall institute proceedings to be adjudicated a voluntary bankrupt, or shall 

consent to the filing of a bankruptcy proceeding against it, or shall file a petition or answer or 
II-6 

consent seeking reorganization or arrangement under the Federal bankruptcy laws or any similar 

applicable Federal or South Carolina law, or shall consent to the filing of any such petition, or shall 

consent to the appointment of a receiver or liquidator or trustee or assignee in bankruptcy or 

insolvency of the Authority or of any of its property, or shall make an assignment for the benefit of 

creditors, or shall admit in writing its insolvency or inability to pay its debts generally as they 

become due, or any action shall be taken by the Authority in furtherance of any of the foregoing 

aforesaid purposes. 

 If an Event of Default has occurred, and shall not have been remedied, the Trustee or the holders of not 

less than 25% in principal amount of the Revenue Obligations then outstanding may declare the principal of all 

Revenue Obligations and the interest accrued thereon to be immediately due and payable, but such declaration 

may be rescinded under certain circumstances. 

 After the occurrence of an Event of Default and prior to the curing of such Event of Default, the Trustee 

may, to the extent permitted by law, take possession and control of the System and operate and maintain the same, 

prescribe rates for capacity or power sold or supplied through the facilities of the System, collect the gross 

revenues resulting from such operation and perform all of the agreements and covenants contained in any contract 

which the Authority is then obligated to perform. In such event, such gross revenues shall be applied, first to the 

payment of the reasonable expenses and liabilities of the Trustee and thereafter to the payment of operating 

expenses and principal of and interest on the Revenue Obligations. After all sums then due in respect of the 

Revenue Obligations have been paid, and after all Events of Default have been cured or secured, to the 

satisfaction of the Trustee, the Trustee is required to relinquish possession and control of the System to the 

Authority. At any such time the Trustee shall be entitled to the appointment of a receiver of the business and 

property of the System, of the moneys, securities and funds of the Authority pledged under the Revenue 

Obligation Resolution, and of the Revenues, and of the income therefrom, with all such powers as the court or 

courts making such appointment shall confer. 

 The Revenue Obligation Resolution empowers the Trustee to file proofs of claims for the benefit of the 

holders of the Revenue Obligations in bankruptcy, insolvency, or reorganization proceedings and to institute suit 

for the collection of sums due and unpaid in connection with the Revenue Obligations, to enforce specific 

performance of covenants contained in the Revenue Obligation Resolution or to obtain injunctive or other 

appropriate relief for the protection of the holders of the Revenue Obligations. 

 No holder of Revenue Obligations has any right to institute suit to enforce any provision of the Revenue 

Obligation Resolution or the execution of any trust thereunder (except to enforce the payment of principal or 

interest installments as they mature), unless the Trustee has been requested by the holders of not less than 25% in 

principal amount of the Revenue Obligations then outstanding to exercise the powers granted it by the Revenue 

Obligation Resolution or to institute such suit and unless the Trustee has refused or failed, within 60 days after the 

receipt of such request and after having been offered adequate security and indemnity, to comply with such 

request. In the event the Trustee has failed or refused to comply with the aforesaid request, the Revenue 

Obligation Resolution provides for the creation of an “Owners Committee.” 

Modifications of the Revenue Obligation Resolution 

Modifications of the Revenue Obligation Resolution and of the rights and duties of the Authority and the 

holders of Revenue Obligations may be made with the consent of the Authority and written consent of the holders 

of not less than a majority of the Revenue Obligations at the time outstanding; provided that no modification shall 

be made which will (i) extend the fixed maturity date for the payment of any Revenue Obligation, or reduce the 

principal amount of or interest rate on any such Revenue Obligation or extend the time of payment of interest 

thereon or reduce any premium payable upon the prepayment or redemption thereof, or advance the date upon 

which any Revenue Obligation may first be called for redemption; or (ii) reduce the percentage of Revenue 

Obligations the holders of which are required to consent to any amendment to the Revenue Obligation Resolution; 

or (iii) give any Revenue Obligation or Revenue Obligations any preference over any other Revenue Obligation or 

Revenue Obligations or reduce the payments required to be made to the Revenue Obligation Fund, without the 

consent of the holders of all the Revenue Obligations affected thereby. 
II-7 

Defeasance 

The obligations of the Authority under the Revenue Obligation Resolution shall be fully discharged and 

satisfied as to any Revenue Obligation and such Revenue Obligation shall no longer be deemed to be outstanding 

thereunder when payment of the principal of and the applicable redemption premium, if any, on such Revenue 

Obligation plus interest to the due date thereof (a) shall have been made or caused to be made in accordance with 

the terms thereof, or (b) shall have been provided by irrevocably depositing with the Trustee therefor in trust 

irrevocably appropriated and set aside exclusively for such payment (i) moneys sufficient to make such payments 

or (ii) Permitted Investments, maturing as to principal and interest in such amounts and at such times as will 

insure the availability of sufficient moneys to make such payment, and, except for the purposes of such payment, 

such Revenue Obligation shall no longer be secured by or entitled to the benefits of the Revenue Obligation 

Resolution; provided that, with respect to Revenue Obligations to be redeemed or otherwise prepaid prior to the 

stated maturities thereof, notice of such redemption or prepayment shall have been given or irrevocable provision 

shall have been made for the giving of such notice. 
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CHARLESTON, SOUTH CAROLINA 

TELEPHONE 843.722.3366 

FACSIMILE 843.722.2266

WEBSITE www.hsblawfirm.com

III - 1 

[Date of Delivery] 

Board of Directors 

South Carolina Public Service Authority 

One Riverwood Drive 

Moncks Corner, South Carolina 29461 

 Re: $______________ South Carolina Public Service Authority Revenue Obligations, 

2014 Series M1 

 We have acted as bond counsel and have examined a certified copy of the Transcript of 

Proceedings and other proofs submitted to us, including the Constitution and Statutes of the State 

of South Carolina, in relation to the issuance by South Carolina Public Service Authority (the 

“Authority”) of the Authority's $_________ Revenue Obligations, 2014 Series M1 (the “2014 M1 

Bonds”) consisting of $__________ Current Interest Bearing Bonds and $________ original 

principal amount of Capital Appreciation Bonds. 

 The 2014 M1 Bonds recite that they are issued for valid corporate purposes of the 

Authority under the authority of and in full compliance with the Constitution and Statutes of the 

State of South Carolina, including Title 58, Chapter 31, Code of Laws of South Carolina 1976, as 

amended, and proceedings of the Board of Directors of the Authority duly adopted, including a 

resolution adopted by the Board of Directors of the Authority on April 26, 1999 (as supplemented 

and amended from time to time, the “Revenue Obligation Resolution”). All capitalized terms used 

herein and not defined shall have the meaning ascribed to such terms in the Revenue Obligation 

Resolution. 

 As to questions of fact material to our opinion, we have relied upon representations of the 

Authority contained in the Revenue Obligation Resolution and in the certified Transcript of 

Proceedings and other certifications of public officials and others furnished to us, without 

undertaking to verify the same by independent investigation. 

 Based upon the foregoing, we are of the opinion, under existing statutes, regulations and 

court decisions, as follows: 

 1. The 2014 M1 Bonds have been authorized and issued in accordance with 

the Constitution and statutes of the State of South Carolina and constitute valid and legally 

binding special obligations of the Authority payable solely from and secured by a lien 

upon and pledge of the Revenue Fund and the revenues of the Authority's System and 

 Appendix III 
Board of Directors 

South Carolina Public Service Authority 

[Date of Delivery] 

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III - 2 

other monies paid into the Revenue Fund (collectively, the “Revenues”), all as set forth 

and provided in the Revenue Obligation Resolution, on a parity with bonds heretofore and 

hereafter issued by the Authority pursuant to the Revenue Obligation Resolution on a 

parity with the 2014 M1 Bonds. 

 2. Interest on the 2014 M1 Bonds is excludable from gross income for federal 

income tax purposes and is not an item of tax preference for purposes of the federal 

alternative minimum tax imposed on individuals and corporations; it should be noted, 

however, that for the purpose of computing the alternative minimum tax imposed on 

certain corporations (as defined for federal income tax purposes), such interest is taken into 

account in determining adjusted current earnings. The opinion set forth in the preceding 

sentence is subject to the condition that the Authority comply with all requirements of the 

Internal Revenue Code of 1986, as amended, that must be satisfied subsequent to the 

issuance of the 2014 M1 Bonds in order that interest thereon be (or continue to be) 

excluded from gross income for federal income tax purposes. Failure to comply with 

certain of such requirements may cause interest on the 2014 M1 Bonds to be included in 

gross income for federal income tax purposes retroactive to the date of issuance of the 

2014 M1 Bonds. We express no opinion regarding other federal tax consequences arising 

with respect to the 2014 M1 Bonds. 

 3. The 2014 M1 Bonds and the interest thereon are exempt from all state, 

county, school district, municipal, and all other taxes or assessments of the State of South 

Carolina, except inheritance, estate, transfer or certain franchise taxes. 

 We express no opinion regarding the accuracy, completeness, or sufficiency of any offering 

material relating to the 2014 M1 Bonds. Furthermore, we express no opinion regarding federal tax 

consequences arising with respect to the 2014 M1 Bonds, other than as expressly set forth herein. 

 It is to be understood that the rights of the owners of the 2014 M1 Bonds and the 

enforceability of the 2014 M1 Bonds may be limited by bankruptcy, insolvency, reorganization, 

moratorium and other similar laws affecting creditors' rights generally and by equitable principles, 

whether considered at law or in equity. 

 Very truly yours,