This Preliminary Official Statement and the information containedherein are subject to completionor amendment. These securities may not be sold nor may offers to buy be accepted prior to the timethe Official Statement is delivered in final form. Under no circumstances shall this Preliminary Official Statement constitutean offer to sell or the solicitation of an offer to buy nor shall there be any saleof 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 decisi ons. Interest on the 2014M1 Bonds is not an item of tax prefer ence in computing the alternative minimum taxable income of individuals or corpora tions. Interest on the 2014M1 Bonds will, however, be included in the computation of certain taxes including alternative minimum tax for corpor ations. See “TAX MATTERS” for a description of certain other federal income tax consequences to certain recipients of interest on the 2014M 1 Bonds. The 2014M1 Bonds and the interest thereon will be exempt from a ll State, county, municipal and school district and other taxes or assessments imposed within the State of South Carolina, excep t estate, transfer and cer tain 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 Stat e of South Carolina (the “Stat e”), customers of the Authority, members of electric cooperatives organized and existing under the la ws of the State, and electric customers of the Bamberg Boar d of Public Works, South Carolina and the City of Georgetown, South Carolina.

The Current Interest Bearing Bonds will be issued in regi stered form in denominations of $500 or integral multiples thereof. The Capital Appreciation Bonds will be issued in regi stered form in denominations of $200 original principal amount o r 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 purchas ed by the Authority on demand by the owner thereof upon the terms and conditions set forth herein. The Authority’s obliga tion to redeem the 2014M1 Bonds at the election of the Bondholder s 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. Inte rest 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 draf t 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 matur ity 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 ple dge 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 sh all 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 subj ect 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 N IKKI H ALEY

Attorney General A LAN W ILSON

State Treasurer C URTIS M. L OFTIS

, J R

. Comptroller General R ICHARD E CKSTROM

Secretary of State M ARK H AMMOND

DIRECTORS

W. L EIGHTON L ORD

, III, Chairman J. C ALHOUN L AND

, IV

W ILLIAM A. F INN

, First Vice Chairman P EGGY H. P INNELL

B ARRY D. W YNN

, Second Vice Chairman D AVID F. S INGLETON

K RISTOFER C LARK C ECIL E. V IVERETTE

EXECUTIVE MANAGEMENT

L ONNIE N. C ARTER ................................................... P RESIDENT AND

C HIEF E XECUTIVE O FFICER

J AMES E. B ROGDON

, J R . ............................................... E XECUTIVE V ICE P RESIDENT AND

G ENERAL C OUNSEL

R ENNIE M. S INGLETARY

, III . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . E XECUTIVE V ICE P RESIDENT

, C ORPORATE S ERVICES

J EFFREY D. A RMFIELD ................................................ S ENIOR V ICE P RESIDENT AND C HIEF

F INANCIAL O FFICER

R OBERT B. F LEMING

, J R . .............................................. S ENIOR V ICE P RESIDENT

, P OWER D ELIVERY

L. P HIL P IERCE ...................................................... S ENIOR V ICE P RESIDENT

, G ENERATION

M ARC R. T YE ....................................................... S ENIOR V ICE P RESIDENT

, C USTOMER S ERVICE

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 CarolinaNo dealer, broker, salesman or other p erson has been authorized by the Auth ority or the Underwriter to give any information or to make any representations with resp ect to the 2014M1 Bonds other than the information and representations contained in this Official Statement, and, if given or made, such other in formation or representations may not be relied upon as having been authorized by the Authority. This Official Statem ent 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 deliv ery of this Official Statement nor any sale made hereunder shall, under any circumstances, create any im plication 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

iRATES 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 PROVI SIONS 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 Obligati ons, 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 su mmary 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., Charlest on, 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 ther eto 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 el ectric 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. Unde r 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 Oblig ations”) 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 Author ity 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 aggr egate principal amount of Revenue Obligations.

1Commercial Paper Notes and Leases. In addition, the Authority has issued indebtedness evidenced by commercial paper notes (the “Comme rcial 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 Pa per Notes and leases is junior to that securing the Revenue Obligations.

The Board of Directors of the Authority has by reso lution 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 availabl e 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 Commercia l 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 pr ior to the payments into the Capital Improvement Fund.

To obtain funds, if needed to repay the Commercial Pa per 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 allo ws the Authority to borrow up to $250,000,000 and expires on September 15, 2014. The agreement with Wells Far go 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 Nove mber 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 loan s is secured by a lien upon and pledge of Revenues pari

passu with the lien upon and pledge of Revenues securing th e 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 porti on of the cost of the Authority’s ongoing capital improvement program. See “CAP ITAL 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 intere st 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 pur chase 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 Aut hority held by the Trustee, as registrar.

2Redemption

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 da ys 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 In terest 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 Inte rest Bearing Bond to be redeemed, together with the interest accrued thereon to the date fixed for redemption.

Purchase of Current Interest Be aring 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 de mand 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 th e 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) th e 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 w ill 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 Ca pital 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 co mmencing 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 th e 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 da ys 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 Apprecia tion Bonds or portions thereof to be redeemed shall be selected by lot by the Trustee, but only in integral mu ltiples of $200 denominations), at a redemption price equal to the Accreted Value on the redemption date of a ny such Capital Appreciation Bond to be redeemed.

3Purchase 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 de mand 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, properl y endorsed with signature guaranteed, which states (i) the CUSIP number, original principal amount, maturity da te and series designation of the Capital Appreciation Bond to be purchased, and (ii) the portion of the origin al 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 w ill be processed in the order of receipt by the Authority of tenders for purchase.

[ Remainder of page intentionally left blank. ]

4Accreted 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 w ith 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

5Accreted 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 w ith 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

6Date 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.]

7Accreted 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 w ith 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

8Date 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 w ill 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.

9LONG-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 expect ed 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 capita l 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 matur ity 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 Authority may obtain a portion of its desired debt alignment by deferring the principal amortization of future 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 Nucl ear 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 sal e of a portion of its ownership interest in Summer

Nuclear Units 2 and 3 to Sou th 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 b illion. 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 f und construction should it be beneficial to do so. See

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

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10DEBT 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 servi ce on Commercial Paper Notes, both of which are junior to debt se rvice on Revenue Obligations. Does not reflect puts subsequent to Decem ber 15, 2013 of Revenue Obligations subject to tender for electiv e purchase. (2) Net of Subsidy Payment (hereinafter defined). Subject to the Authority’s compliance with certain requirements under the Ame rican 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 e qual 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 Budge t 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 qua lified bonds. The sequestration reduction rate of 7.2% has been applie d to the July 1, 2014 and January 1, 2015 Subsidy Payments resp ectively, and the debt service on Revenue Obligations in cal endar 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 th e year due rather than on an accrual b asis 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 s ecured by a lien upon and pledge of, the Revenues on a parity with the lien and pledge securing Revenue Obliga tions heretofore and hereafter issued pursuant to the Revenue Obligation Resolution, senior to (i) payments re quired to be made from or retained in the Revenue Fund to pay expenses of operating and maintaining the System, a nd (ii) the payments into the Lease Fund and the Capital Improvement Fund heretofore established and con tinued under the Revenue Obligation Resolution. See “FINANCIAL INFORMATION.” In the Revenue Obligation Re solution the Authority has covenanted not to incur any indebtedness senior to the lien of the Revenue Obligations.

The Revenue Obligations, including the 2014M1 Bonds, ar e 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 Re venues 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 unde r 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 Aut hority shall establish, maintain and collect rents, tolls, rates and other charges for power and energy and a ll other services, facilities and commodities sold, furnished or supplied through the facilities of the System which sha ll 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 Re venue Obligation Resolution, (ii) into the Lease Fund, and (iii) into the Capital Improvement Fund pursuant to th e 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, replacem ents and renewals thereof; (e) to pay all taxes, assessments or other governmental char ges 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.

12Additional 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 secu ring the Revenue Obligations. In addition, the Authority may issue obligations secured by a pledge of revenues de rived from separate utility systems not included in the System. See Appendix II -- “SUMMARY OF CE RTAIN 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 th e 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 RE VENUE OBLIGATION RESOLUTION.”

ORGANIZATION AND MANAGEMENT OF THE AUTHORITY

The Act contains provisions governing the compositi on, qualifications, appointment and duties of the Authority’s Board of Directors. The Governor appoint s members, and the State Regulation of Public Utilities Review Committee (“PURC”) screens appointees to determ ine 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 dir ector may be held accountable for his actions or inactions

as a director.

The Board consists of twelve members who re side in South Carolina as follows: one from each congressional district of the State; one from each of th e counties of Berkeley, Horry and Georgetown who reside in the territory of the Authority and are customers of th e Authority, and two from the State at large, one of whom

shall be chairman. Two of the directors must have subs tantial work experience within the operations of electric cooperatives or substantial experience on an electric coope rative 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 un til 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 appoint ed and found qualified by the PURC while the State Senate is not in session may serve as director in an interim cap acity. Directors may be removed from office only for cause.

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13Present directors are listed below. W. Leighton Lord, III became Chairman on June 6, 2013, creating a vacancy for the Sec ond 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 Vivere tte 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 Dir ector 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 Congre ssional District, appointed Merrill Floyd as Director for the Seventh Congressional District, appointed Dan Ra y 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 screen ing 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 a ppointed 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 Pr esident, 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-pr ofit 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 Admi nistration and a Masters in Business Administration from

The Citadel.

14James 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 la w 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 Manage r 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 Administra tion 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 Fi nancial Planning. He received a Bachelor of Science degree in Business and a Masters in Business Admini stration 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 ha s held various positions including Manager of Transmission Operations, Superintendent of System Substation Maintena nce 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 Servi ces and Manager of Cross Station Construction. He received a Bachelor of Science degree in Mech anical 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 Ma nager of Wholesale Markets. He received a Bachelor of Science degree in Electrical Engineering and a Ma sters 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 th e following officials of the State: the Governor, the Attorney General, the State Treasurer, the Comptroller Ge neral 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 pr oduction, transmission and distribution of electrical energy, both at wholesale and retail, to citizens of Sout h Carolina. In 2013, the Authority’s kilowatt-hour (“kWh”) energy sales were comprised of 57.8% to wholesale cust omers, 28.1% to large industrial customers and 14.1% to residential, commercial and other customers. The Author ity is one of the nation’s largest municipal wholesale utilities, whose System serves directly or indirectly a pproximately 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.”

15The Authority's direct customers currently include 28 large industrial customers, Central Electric Power Cooperative Inc. (“Central”), and two municipal electric syst ems, the City of Georgetown and the City of Bamberg. Central is an association of 20 electric distribution coope ratives, including the five electric distribution cooperatives that were formerly members of Saluda River Electri c 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 in cludes 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 i ndustrial 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 ta ble below lists each of the Central Cooperatives, the location of their headquarters, and the number of custom ers 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 am ended 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, establis hed 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.

16September 2009 Agreement. In September 2009 Central and the Authority entered into an agreement (the “September 2009 Agreement”) that, among other things, provi ded 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 beginni ng 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”) th at 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 no tice of termination no later than Decem ber 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 servi ce 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 pr oduction 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 exis ting system resources, including Summer Nuclear Units 2 and 3. The May 2013 Revision formalizes the resource planni ng process and outlines how the parties will jointly plan and determine the need for new resources. The May 2013 Re vision also contains provisions that allow Central to decide to participate or not participate in major ne w resources which were not co mpleted or under construction as of January 1, 2013. If Central deci des to participate in a resource, the costs for the new resource are included and shared under the Central Agreement. If Central decide s 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 ali gn 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 re quirements 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 Septembe r 2009 Agreement referenced above, and small amounts purchased from others.

Under State law, the Authority may only serve dir ectly 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 Aut hority, the Authority may sell electri cal service to new customers from its major transmission lines in areas outside the Author ity’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 Palme tto Economic Development Corporation, to benefit the State, the Authority and Central. Formed in Septembe r 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 th e Authority. In February 2012, the Authority and Central announced economic development rates for new and expande d large industrial loads to further enhance their economic development efforts.

17Wholesale - 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 cont racts. 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 pow er 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 s upplemental 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 serv es 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 cu stomers and certain other customers are made pursuant to rate schedules established from time to time by the Author ity. The vast majority of such rate schedules include monthly automatic fuel adjustment and demand sales adjustme nt 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 fo r large industrial customers which contract for a minimum of 1,000 kilowatts (“kW”). The Authority requires that su ch customers enter into contracts for initial periods of not less than five years. All contracts contain rate pr ovisions 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 schedul es. The average cost per kWh varies depending upon the customer's usage and load factor.

Sales to large industrial customers during 2013 repres ented 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 wh ich no one customer represents more than 1.5% of sales. Of the 21.2% of revenues from sales, approxima tely 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. Appr oximately 25% of the load is currently served under the Authority’s firm industrial rate schedule, with the ma jority 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 co mpany, 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.

18In addition to its standard termination provisions, the contr act 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 roll over terms thereafter. The contract currently provides for delivery of approximately 300 MW of power, the major ity 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 Au thority’s Board of Directors approved a series of two base rate adjustments for its retail, industrial and munici pal customers. The adjustments increased total charges for customers an average 3.5 percent each year for a total in crease of 7 percent to ensure rates are at least adequate to provide revenues sufficient to pay debt service, the co st of operation and maintenance of the Authority’s System, and meet the Revenue Obligation requirements for transfer s 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 indus trial 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 fo r 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 ad justment 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 aver aged 5.14 cents per kWh, and revenues from sales to residential, commercial, small indus trial 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 fi rm service at selected usage levels with the average monthly bills of the three investor-owned utilities that serv e 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.

19As 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

20POWER 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 B each 1962 20 16 Oil/Gas

Combustion Turbines Nos. 3 and 4 . . . . . . . . . . . . Myrtle B each 1972 40 38 Oil

Combustion Turbine No. 5 . . . . . . . . . . . . . . . . . . Myrtle B each 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) . . . . . . . . . . . . . . . . . . Jenkinsv ille 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 . . . . . . . . . . . . . . Bis hopville 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 a nd 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 determin ed by the Authority’s management and in compliance with applic able

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”).

21Existing 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 hydr o electric generating facility which it leases from Greenwood County, South Carolina and 75 MW of biomass capacity and associ ated 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 out put 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 com bustion turbine resource. This purchase is anticipated to provide a summer capability amount of 155 MW. The Aut hority 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 gene ration, 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 dir ect 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 cl assified 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 opera tion while complying with environmental requirements.

All Authority operated units are maintained with computerized maintenance management systems and the use of preventive, predictive, and proactive maintena nce practices to achieve high reliability and efficiency at low maintenance cost. In its maintenance program, the Au thority utilizes technologies such as vibration analysis, oil analysis, thermography, laser alignment, and non-destru ctive 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.”

22Summer Nuclear Unit 1. The Authority owns a one-third undivided interest in Summer Nuclear Unit 1 which has a pressurized water reactor with a maximu m dependable rating of 954 MW net. SCE&G owns the remaining two-thirds interest and operates and mainta ins 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 operati on, 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 Genera tion -- 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. Th e 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, expect ed 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 fo r 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 Contr act”) with the DOE for spent fuel and high level waste disposal for the operating life of Summer Nuclear Un it 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 bega n 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 th at would be necessary for continued operation of certain units. In 2012, the Authority’s Board of Directors author ized retirement of six electric generating units: Grainger Generating Station Nos. 1 and 2, and Je fferies 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 Ge nerating Station Nos. 3 and 4 ceased operations and were officially retired on December 31, 2012. Appropriate notif ications 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.

23Renewable 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 sy stem which includes lines owned and leased by the Authority as well as those owned by Central. The tran smission 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 Author ity operates 105 transmission substations and switching stations serving 85 distribution substations and 465 Cent ral 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 conti ngency conditions that are outlined in electric system reliability standards adopted by the North American El ectric 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 locati ons; 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 w ith 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 servi ce 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 Reliab ility 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, Briarc liffe, Surfside Beach, Atlantic Beach, Pawleys Island, unincorporated areas along the Gr and Strand and portions of rural Georgetown and Horry

Counties. See “CUSTOMER BASE.”

General Plant

The Authority owns general plant consisting of o ffice 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 ga rage, maintenance facilities and warehouse facilities.

24Fuel Supply

During 2013, the Authority's energy supply, includi ng 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 acqui red 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 car s 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 a nd quality requirements, the Authority uses a combination of these coal supplies with long-term and short-term contr acts 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 imp act 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 projec tions based on gas prices and forward price curves available at the time the budget is developed and should ther efore factor in coal to gas generation switching based on economics. Using this methodology, the Authority ha d 224 days of coal on hand as of Decem ber 31, 2013. In terms of tonnage, as of December 31, 2013, the Author ity had approximately 4.40 million tons of coal on hand.

Sulfur dioxide (“SO 2 ”) 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 Transcontinen tal 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.

25Commodity Risk Management. The Authority’s Board of Directors has approved a policy that deals with the philosophy, framework and delegation of authority nece ssary 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 commod ity risk hedging program, and by taking advantage of market opportunities, such as purchasing and blending off-sp ecification coal when the economics are favorable.

The Authority has determined that all transacti ons 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 (“N PPD”), Public Utility District No. 1 of Cowlitz County, Washington and American Municipal Power.

TEA markets wholesale power and coordinates the ope ration of the generation assets of its members to maximize the efficient use of electrical energy resour ces, reduce operating costs and increase operating revenues of its members. TEA is expected to accomplish the fore going without impacting the safety and reliability of the electric system of each member. In addition, TEA purchas es 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 investment s 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, Gaines ville Regional Utilities, JEA, MEAG Power, NPPD and

Orlando Utilities Commission.

Colectric is a membership-driven nonprofit corpora tion headquartered in Jacksonville, Florida which serves the public power industry in a variety of project a nd business management roles. They help their members leverage economies of scale to control operations and ma intenance costs and streamline power generation projects.

Currently, the Authority participates in two of Co lectric’s initiatives. The first involves managing the major gas turbine overhauls, thereby promoting the shari ng of spare parts and technical expertise. The second initiative is a strategic sourcing initiative, intended to achieve major cost savings through volume purchasing leverage.

26CAPITAL 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, a pproximately $167,000,000 for environmental compliance expenditures, and approxima tely $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 bo rrowed 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-te rm 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 n eed 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 ar e 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 regulati on and legislation typically associated with fossil fired resources such as those targeting carbon and SO 2 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 previous ly anticipated sales to Central, as described under “CUSTOMER BASE - Wholesale,” and new EPA regulati ons which increase the operating costs of coal-fired generating units as described under “REGULATORY MATTER S -- Environmental Matters.” As a result, the Authority will retire six electric generating units (See “POWER SU PPLY AND POWER MARKETING-- Existing Power Resources”) and has entered into an agreemen t 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.”

27Summer 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 to wers, intake and discharge structures, a 230 kV switchyard for transmission access, and numerous ancillary stru ctures 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 incorporat ed 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 thr ough 19. The amendment replaces the combined license information items and design acceptance criteria (“DAC”) w ith specific design information, addresses the effects of the impact of a large commercial aircraft, incorporat es design improvements, and increases standardization of the design.

The AP1000 is the first and only reactor in its cl ass of technological development, referred to as “Generation III+”, to receive certification from the NRC.

28The AP1000 is a pressurized water reactor with passive sa fety 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 applica tion 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. Th e NRC also directed the Office of Ne w 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 Engin eering, Procurement, and Construction ("EPC") Agreement, with a Consortium consisting of Westinghouse Electric Comp any, LLC and Stone & Webs ter, Inc. Pursuant to the EPC Agreement, the Consortium will supply, construc t, 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 associ ated 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 se veral 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 maintain ing 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 dama ges and for warranty claims is subject to a cap. The payment obligations of Westinghouse are guaranteed by To shiba Corporation, and the payment obligations of Stone & Webster are guaranteed by Chicago Bridge & Ir on Company. The Authority and SCE&G may, at any time, terminate the EPC Agreement fo r their convenience and without cause , provided that the Authority and SCE&G will pay certain termination costs and, at certain st ages 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 pr ovision 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

29would be acquired in three stages, with 1% to be acquire d at the commercial operation date of the first new nuclear unit, which is anticipated to be in late 2017 or the firs t quarter of 2018, an additional 2% to be acquired no later than the first anniversary of such commercial operation da te 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 conveye d 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 th e 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), continuati on for design work, project management, engineering and administrative support to procure long lead time equipmen t, construction mobilization, site preparation, site infrastructure development, and installation of constr uction 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 construc tion 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 m odifications of the shield building and certain prefabricated structural modules and unan ticipated 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 dolla rs). As a result of this settlement, the substantial completion dates for Summer Nuclear Units 2 and 3 ch anged from April 2016 and January 2019 (respectively) to March 2017 and May 2018.

The Consortium has experienced delays in the schedul e for fabrication and delivery of sub-modules for

the new units. After examination of this issue and c onsultation with the Consortium, in June 2013, SCE&G announced that the substantial completion of Summer Nucl ear Unit 2 is expected to be delayed from March 2017 to late 2017 or the first quarter of 2018 and the substan tial completion for Summer Nuclear Unit 3 is expected to be similarly delayed.

Since August 2013, the Consortium has experienced a dditional delays in sub-module fabrication and deliveries but reconfirmed the substantial completion date s announced in June 2013. The fabrication and delivery of sub-modules are a focus area of the Consortium, incl uding sub-modules for module CA20, which is part of the auxiliary building, and CA01, which houses components in side 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 r eady for placement on the nuclear island of the first new unit in the second quarter of 2014. In addition, the deliver y 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 nece ssary 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 w ill result in increased project costs. However, based on SCE&G's estimate of its share of delay-related costs associ ated with the new units, the Authority estimates its share

30could be approximately $150 million. This amount is w ithin the Authority’s current approved budget and would not result in an increase to the total budget. The Aut hority 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 re garding 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 cost s, 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 deta iled 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 re vised fully integrated construction schedule that will provide detailed and itemized information on individual budge t 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 revise d 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 genera ting 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 a nd labor, (b) work stoppages, (c) regulatory matters, (d) unforeseen engineering problems, (e) unanticipated increas es 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 St ates using advanced designs such as the Westinghouse AP1000 reactor. Therefore, estimating th e 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 a ssist 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 opera tions, engineering, construction, maintenance, quality assurance and nuclear regulations. This expertise is disp atched 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 closel y 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 cu rrently under development at nearby Plant Vogtle in Waynesboro, Georgia.

31HISTORICAL SALES

Historical Demand, Sales and Revenues

The following table sets forth the territori al peak demand including firm off-system sales to other utilities,
if any, on the Authority's System as well as the milli on 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 sa les 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

32FINANCIAL INFORMATION

Historical Operating Results

A summary of the Authority's revenues available fo r 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 Amer ica 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 lie u of taxes paid by Specia l

Reserve Fund.

(3) This category of bonds is no longer outstanding.

(4) The Revenue Obligation Resoluti on provides for debt service of Re venue Obligations to be paid from Revenues prior to payment s for operating and maintenance expenses. See "S ECURITY FOR THE 2014M1 BONDS - Rate Covenant."

(5) Calculation of coverage does not include debt service on Co mmercial Paper Notes and Other.

33REGULATORY MATTERS

The Electric Utility Industry Generally

The electric utility industry in general has been a ffected 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 utilizati on 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 el ectric (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 compe tition from independent power producers, marketers and brokers, (f) self-generation by certain industrial, commerc ial 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 pub lic domain, and potential purchasers of the 2014M1 Bonds

should obtain and review such information.

Environmental Matters

Both the EPA and the DHEC have imposed vari ous environmental regulations and permitting requirements affecting the Authority’s facilities. Th ese regulations and requirements relate primarily to airborne pollution, the discharge of pollutants into wate rs 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 operati ons will not encounter occasional technical difficulties or that necessary permits and authorizations will be r eceived. 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 regard ing 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. Pu rsuant to the Clean Air Act (“CAA”), as amended, the EPA promulgated primary and secondary nati onal ambient air quality standards (“NAAQS”) with respect to certain air pollutants, including particulate matter, SO 2 and nitrogen oxide (“NO

x ”). 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”), whic h has been approved by the EPA, generally designed to achieve the primary and secondary air quality st andards. The EPA also promulgated the New Source Performance Standards (“NSPS”) regulations establis hing stringent emission standards for particulate
matter, SO 2 and NO

x emissions for fossil-fuel fired steam generators, and revised these standards in 1979 and 2005. Congress has enacted comprehens ive 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 NO

x and SO 2 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 sc heduled to take effect January 1, 2012. On

34December 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 simila r 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 (“CO 2 ”) for new affected fossil fuel-fired electric utility generating units (“EGUs”). The EPA proposed these requirements because CO 2 is a greenhouse gas (“GHG”) and fossil fuel-fired power plants are the count ry’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 th e 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 CO 2 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 CO 2 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 CO 2 or equivalent per year. This reporting requirement applies to the Authority’s larger generating facilities, and electrical tr ansmission 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, re gulations, or guidelines, as appropriate, by June 1, 2014, for existing, rec onstructed or modified plants. The memo directed the EPA to issue final rules or guidelines for existing pl ants by June 1, 2015. On January 8, 2014 the EPA published in the Federal Register the proposed CO 2 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 s ources 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 author ity by the EPA and administers the program for the State. Industrial wastewater discharges from a ll stations and the regional water plants are governed by NPDES permits. The DHEC also has permitting authority for stormwater discharges and the

35Authority manages stormwater pursuant to th e 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 substa nces 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 Comprehe nsive 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 envir onment, including water, land and air, and imposes liability upon any generators, transpor ters 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 in formation. Additionally, the EPA regulations under the Toxic Substances Control Act impose stringe nt requirements for labeling, handling, storing and disposing of polychlorinated biphenyls (“PCB”) and associated equipment. There are regulations covering PCB notification and manifesting, restric tions 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 SubtitleC, 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 d ecree filed in US District Court for the District

36of 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 Cro ss Generating Station. The Authority expects to complete construction and place the landfil l 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 Wa ter Systems, generating stations, substations and other auxiliary facilities. DHEC has regulatory author ity 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 implem entation of federal drinking water regulations.

FERC Hydro Licensing

The Authority operates its Jefferies Hydro Stati on 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 a nd 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 reli censing 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 s ubmitted mandatory fishway conditions under §18 of the FPA and flow recommendations under §10 of that Act that ar e inconsistent with the settlement agreement.

In November 2007, FERC requested that NMFS undert ake 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 opi nion containing recommendations for the endangered shortnose sturgeon. The recommendations, if adopted, w ould result in substantial additional costs for operating the project. The Authority provided a response to t hose 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 sta ndards, including critical infrastructure protection standards, for the bulk power system. The critical in frastructure protection standards focus on controlling access to critical physical and cyber security assets. Complia nce with these standards is mandatory. The maximum penalty that may be levied for violating a NERC reliabil ity standard is $1 million per violation, per day. The Authority has self-reported some violations of NERC reli ability 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 po ssible to predict whether the Authority will have future violations or what the fines for such violations might be.

37Nuclear Matters

Summer Nuclear Unit 1 is subject to regulation by th e 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 fe deral 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 in to 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 fu ture costs for operating nuclear plants. Specifically, the NRC is performing additional operational and safety re views of nuclear facilities in the U.S., which could potentially impact future operations and capital requireme nts. 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 fo r 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 eval uations 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 othe r 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 de termined at this time; however, management does not currently anticipate that the associated compliance co sts 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 Author ity, 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 additi onal $10.4 million in costs and attorneys’ fees to the plaintiffs in August, 2011. The Authority pursued an i ndemnification 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 resu lt 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.

38Grainger Ash Pond Litigation. In June 2012, several environmen tal 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 occurre d 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 injuncti ve 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 fo r 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 c ould 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 inform ed that a settlement, subject to court approval, has been reached in the underlying class action lawsuit agains t 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 Manage ment, 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 thereu nder (the “Regulations”) and further subject to certain

considerations described in “Collate ral Federal Tax Considerations” belo w, 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. Inte rest on the 2014M1 Bonds will not be treated as an item of tax preference in calculating the alternative minimum ta xable income of individuals or corporations; however,

interest on the 2014M1 Bonds will be included in the calcula tion of adjusted current earnings in determining the alternative minimum tax liability of corporations. The C ode contains other provisions that could result in tax consequences, upon which no opinion will be rendered by B ond Counsel, as a result of (i) ownership of the 2014M1 Bonds or (ii) the inclusion in certain computati ons 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 lega l authority, covers certain matters not directly addressed by such authorities, and represents Bond Couns el'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 suppl ement 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 repr esentations and covenants that it deems relevant to such opinions.

39The opinion of Bond Counsel described above is subject to the condition that the Authority comply with all requirements of the Code and the Regulations, incl uding, without limitation, certain limitations on the use, expenditure and investment of the proceeds of the 2014M 1 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 covenant ed 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 co rporations, certain S corporations, indi vidual 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 expre sses no opinion concerning such collateral income tax consequences, and prospective purchasers of 2014M1 B onds should consult their tax advisors as to the applicability thereof.

Future legislation, if enacted into law, or clar ification of the Code may cause interest on the 2014M1 Bonds to be subject, directly or indirectly, to federal in come 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 legi slation which if passed might adversely affect the tax treatment of interest on the 2014M1 Bonds. Prospectiv e purchasers of the 2014M1 Bonds should consult their own tax advisors regarding any pending or proposed federa l 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 in come 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 ex amination by the IRS. The IRS has taken the position that, under the standards of practice before the IRS, Bond Couns el must obtain a waiver of a conflict of interest to represent an issuer in an examination of tax exem pt 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 connec tion with an audit examination of tax-exempt bonds is difficult, obtaining an independent review of IRS positi ons 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.

40State Tax Exemption

Bond Counsel is of the further opinion that the 2014M 1 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 2014M 1 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 th ereon under the laws of any other jurisdiction.

APPROVAL OF LEGAL PROCEEDINGS

Haynsworth Sinkler Boyd, P.A., Charleston, South Ca rolina, 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 matt ers of opinion or estimates, whether or not expressly so stated, are intended merely as such and not as repr esentations 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[THIS PAGE INTENTIONALLY LEFT BLANK]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

Rece ivables, 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 (3,15 0,020) (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 r efunded and defeased debt 119,868 138,072

Total deferred outflows of resources $ 139,235 $ 172,963

Total assets & deferred outflows of r esources $ 10,707,596 $ 9,762,53 2

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

(Thousand s) 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 $ 8,14 6 $ 3,423 Nuclear decommissioning costs 185,849 196,252

Total deferred inflows of resources $ 193,995 $ 199,675

NET POSITION

Net invested in c apital 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 p osition $ 10,707,596 $ 9,762,532I

- 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 de crease 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 accom panying 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 ope rating activities
Receipts from customers $ 1,832,536 $ 1,891,420
Payments to non

- fuel suppliers ( 262,973 ) (516,867)
Payments for fuel (736,02 2 ) (821,705)

Pur chased 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 us ed 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 (16 7,412) (151,210)
Interest paid on long

- term debt (279,148) (265,682)
Interest paid on commercial paper and other (5,98 3 ) (5,000)
Construction and betterments of utility plant (730, 119 ) (488, 236 )

Bond issuance and other related costs ( 34,217 ) 50,120

Other

- net (60,48 7 ) (23,048 )
Net cash used in capital

- related financing activities ( 224, 823 ) (314, 374 )

Cash flows from inves ting ac tivities

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) 4 0,751

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 c ompanies (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 equi valents

Current

Unrestricted cash and cash equivalents $ 172,738 $ 203,591
Restricted cash and cash equivalents 182,455 273,542

Noncurrent

Restricted cas h and cash equivalents 1,535 1,911

Cash and cash equivalents at the end of the year $ 356,728 $ 479,044I

- 6 

# N OTES

N OTE 1

– S

UMMARY OF SIGNIFICANT ACCOUNTING POLICIES :

A

- Reporting Entity

- The South Carolina Public Service Authority (the A uthority 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 Director s (Board) is appointed by the Governor of South Carolina with the ad vice and consent of the

Senate. The purpose of the Authority is to provide electric power and wholesale water t o the people of South

Carolina. Capital projects are funded by b onds , comme rcial 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 recor ds 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 proprie tary 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

R egional W ater Sy stem s a fter elimination of inter

- com pany 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 system s

.

The Authority also complies with policies and practice s prescribed by its Board and practices commo n in both

industries. As the Board is authorized to set rates, the Author ity follows GASB 62. This s ta ndard provides for the reporting of assets and liabilities consistent with the economi c 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 affect s 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 expens es d uring 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 S tatements 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 constitution al 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 Au thority considers highly liquid investments with original maturities of ninety days or less and cash on deposit with financial institutions as Unr estricted and R estricted cash and cash equivalents.



### F

- Inventory

- Material and fuel inventor ies are carri ed 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 rec overed currently through rates. The costs of maintenance, repairs and minor replacements are charged to appropriate operation an d maintenance expense accounts. The costs of renewals and betterment s are capitalized. The original cost of utility plant retired and the cost of removal, less salvage, are charged to accumul ated depreciation.



### H

- Depreciation

- Depreciation is computed using composite rates on a straight

- line basis over the estimated

useful lives of th e various classes of the plant. Composite rates are applied to the gross plant balance of various

classes o f assets which includes appropriate adjustments f or cost of removal and salvage. The Authority periodically has depreciation studies performed by independent parties to assist management in establishing appropriate c omposite depreciation rates.

Annual d epreciation 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 revisi ons 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:

Balanc e 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 f or 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 u pdates include a poten tial 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 Jeff eries Generating Station began in late 2 013. 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 requi rements. It should be note d 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 o wnership interest s 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

Gai nesville 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 acti vities 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 guaran tees 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 tha t payments made under the TEA member guarantees would be equalized ratably, based upon each member’s eq uity ownership interest. After such contributions have been a ffected, the Authority would only have recourse again st TEA to recover am ounts paid under t he guarantee. The term of this guarantee is generally indefinite, but the Authority has the ability to terminate its guarantee obligations by provid ing advanceI

- 9

notice to the beneficiaries thereof. Such termination of its guarantee obligations only applie s to TEA transactions not yet entered into at the time the termi nation 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 tradin g positions at a point in time. The

for mula was approved by the Authority’s Board . A t December 31, 20 1 3 , 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 interest s w ere as fol lows:

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

N ebraska 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 participat e in C olectric 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 spar e parts and technical e xpertise. 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 turbi ne 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 agr eements betwe en Colectric and the Authority. These indemnifications are within the scope of FASB ASC 952

. The Authority’s initial investment in Colec tric was $413,000. The balance in its member equity account at December 31, 201 3 and 201 2 was approximate ly $ 19 6 ,000 and $ 1 92 ,000

, respectively

. Since 2001, c umulative 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 Solution s. 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 o f electric power on behalf of the corporation’s c lients; (2 ) coordinate the purchase and sale of

na tural gas relating to fuel for c lients’ generation of electric energy or relating to c lients’ operation of a retail gas distribution system; and (3 ) provide consulting and software services to c lients.

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 st art

- up costs pertaining to TEA Solutions. Neither fin ancial statements nor an estimate of the Authority’s share of start

- up expenses were available a s 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
consumpt ion 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) unamort ized 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 Auth ority 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 Statem ents 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 Statement s 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 $ 54,624I

- 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 Aut hority, 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, 201 3 and 201 2 is below:

Cash Flow Hedges and Summary of Activity

Years Ended December 31, 2013 2012

Account Classifica tion (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 Ope rating 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

re corded 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 operati ng expenses as fuel is consumed. Fuel expense for all customers is billed utilizing rates and contracts, the majority of which include fuel adjustment provis ions 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

co sts 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 treatme nt with regards to these costs.

Consistent with prior accounting periods, una mortized debt discounts, premiums and expense s are amortized to income over the terms of the related debt issues. Gains or losses on refunded and extinguished debt are

amortize d to earnings over t he 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 be st 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 othe rs must be paid over semiannually to the State Treasurer for the general funds of the State. Nothing in this section shall prohibit the A uthority from paying to the State each year up to one percent of its projected operating revenues, as such revenues wo uld 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 201 3 and 201 2 totaled approximate ly $ 20.4 million and $ 19.6 million

, re spectively

.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 Stat ements 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 Effec tive 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 deferre d 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 Beginni ng 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.

St atement 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, Pensi on 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 o f 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 en tities.

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 financ ial 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 opera tions.

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 a ccounting 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 factor s 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 applic ation 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 

# N OTE 2

– C

OSTS TO BE RECOVERED FROM FUTURE REVENUE :

The Authority’s rates are established based upon debt service a nd operating fund requ irements. 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 A uthority’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)



# N OTE 3

– C

APITAL ASSETS

:

C apital asset activity for the year s ended December 31, 20 1 3 and 20 1 2 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 ,150,0 20 )

Total utility plant

- net 4,297,851 (44,1 94 ) 14,6 79 4,268,336

Construction work in progress 1,643,507 644,343 (187,219) 2,100,631

Other physical prop erty

- net 6,560 0 (476) 6,084

Totals $ 5,947,918 $ 600, 149 $ (173,0 16 ) $ 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

- ne t 6,783 0 (223) 6,560

Totals $ 5,092,749 $ 1,488,829 $ (633,660) $ 5,947,918I

- 15 

# N OTE 4

– C

ASH AND INVESTMENTS HELD BY TRUSTEE AND

FUND DETAILS

:

All cash and investmen ts 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 agree ments, the Enabling Act included in the South Carolina Code of Laws (the Enabling Act) or by management directive. Restricted funds have constraints p l aced on their use (see Note 1

- D

– Restricted Assets ). The use of unrestricted funds may be either desig nated for a specific use by management directive or undesignated, but are available to provide liquidity for operations as

needed.

Following are t he details of the Authority’s funds which are classified in the accompanying financial statements as

unrestri cted 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 10,780 229,403 240,1 83 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:

De bt 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 restricte d cash and investments. This resulted in material changes to the classification of t hose 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 ) de co mmissioning 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 ar e 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 secti ons 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. T he 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 th e Revenue Obligation Resolution. Authorized investment types include Federal Agency Securities, State of South Carolina General Obligation Bonds and U.S. Treasury Obligations, a ll of which are limited to a 10 year maximum maturity in all portfolios, excep t the decommissioning f unds. 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

n on

- 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)

To tal 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

perce nt of the cost of the repurchase agreement and are delivered by broker/dealers to the Authority's custodial agents.I

- 17

Common d eposit and investment risks related to credit risk, custodial credit risk, concentration of credit risk, interest

rate r isk 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 statist ical 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

- Inve stments

- 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 fi nancial 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

Concentrat ion 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 Aut hority 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 25 5,042 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

Maturit y (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

R epurchase 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 ar e 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 val ue 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 anticipat ed 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

ad versely 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 DE

BT :
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) (%) (%) Cap italized 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 10 0

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 10 0 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

- Whol e 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

20 08 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 1.6 0

- 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

2 012 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 Prem ium

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 t he 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 $ 1,918,76 4 $ (1,029,065) $ 6,447,49 2 $ 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

Matur ities 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 Obligation s 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

20 19

- 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 201 4

- 2016 include projected interest for 201 3 Taxable Series D (LIBOR Index Bonds). (2) Does not reflect impact of subsidy i nterest 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 Dec ember 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

20 12 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 14,44 6 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 $ 119,868I

- 21



### Analysis of Prior Year Current Portion of Long

- term

As a part of its long

- term ca pital 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 Curre nt 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 o riginal minib ond 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 analysi s 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.



### Reconci liations 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 c ost $ 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 $ 265,682I

- 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 distribut ion 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:

P rior to distribution to the State 1.52 1.44

A fter distribution to the State 1.46 1.38

Including commercial paper and other:

P rior to distribution to the State 1.49 1.41

A fter distribution to the S tate 1.43 1.36I

- 23

T h e 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, 20 1 3 and 20 1 2

, respectively.

Bond m arket transactions for the year ended December 31, 201 3 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 A ppreciation 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 a nd 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

Author ized: 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, 20 1 3 and 201 2 , the Authority was in compliance with all debt covenants. The Au thority’s bond indentures provide for certain restrictions, the most significant of which are: (1) t he Authority covenants to establish rates sufficient to pay all debt service, r equired lease payments, capital improvement fund requirements and all costs of operation and maintenance of the Authority’s

electric and water system s 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 de bt (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) payme nt of expenses for operating and maintaining the System s ; (2) payments for debt service on c apitalized l eases ; (3) payments for debt service on commercial paper; and (4) payments made in to the Capital Improvement Fund.

Bonds Outstanding Summary

As of D ecember 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. Wanda

CollinsI

- 24 

# NO TE 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. T he 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 an d 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. Th ese agreement s are used to s upport the Authority’s issuance of commercial

paper. There were no borrowings under the agreement s during 20 1 3 or 201 2

.



# N OTE 7

– SUMMER NUCLEAR STATION:

Unit 1

- The Authority and South Carolina Electric and Gas (SCE&G) are parties to a joint ownershi p 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, managem ent, 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

- ye ar 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

includ e a component for estimated disposal expense o f 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

- lo ad through 201 7

. 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

decom mission 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 199 0. 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 decommis sioning study completed in 20 12 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 20 12 dollars

. As deposits are

mad e, the Authority debits FERC account 532

- Maintenance of Nuclear Plant, an amount equal to the deposits

made to the int ernal and external trust funds. These costs are recovered through the Authority’s rates.

Based on current decommissioning cost estim ates, these funds, which totaled approximately $ 185.0 million (adjusted to market) at December 31, 20 1 3 , 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 construct ing and planning to operate two additional nuclear
generating units (Summer Units 2 and 3) at V

. C

. Summer Nuclear St ation and submitted an applica tion to the

NRC in March 2008 for a combined Const ruction and Operating License ( COL) for each of the two new units

. On May 22, 2008, th e Authority’s Board authorized the Authority to execute a Limited Agency Agreement appointing

SCE&G to act as the Autho rity’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.), f or the engineering, procurement and construction of two 1

, 10 0 MW nuclear generating units. Chicago Bridge & Iron Company acquired T he 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 und ivided 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 repla ce the Amende d 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 bi llion 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 p art of its capital improvement p rogr am, the Authority has evaluated its level of pa rticipation in the new units.

D ue to developments since initiation of the project, the Authority is taking actions necessary to reduce its 45 percent ownership interest. Beginning 2011, the Authority deferr ed a portion of interest expense representing the

amount related to the assumed ownership reduction. I n 2013 , the Authority continued deferring and began capitalizing portions of related interest expense based on revised ownership assumptions

.



# NOTE 8

– LE

ASES:

The Authority has remaining capital lease contracts with Central Electric Power Cooperative, Inc. (Central), covering transmissio n 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 t he 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 a t the termination of the lease. The Authority plans to exercise each and every opt ion to acquire ownership of such facilities prior to expiration of the leases.

Total minimum lease payments on Central leases at December 31, 20 1 3 are as follows:

Year Ending December 31, (Thousands)

2014 $ 251
Less amounts representing interest 7 Principal payments $ 244

I nformation related to property under capital leases and operating lease payments follows:

Years Ended December 31, 2013 2012

(Millions)

Property under capital leases:

Property bala nces $ 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 ini tially 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.
Hydro electric 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 expensesI

- 27 

# N OTE 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 w hich 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 re ceive s 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 t erms of the Coordination Agreement, has the right to audit costs billed to them through the Coordination Agreement

. Any d ifferences found as a result of this process are accrued if they are probable and

estimable

. To the extent that differences arise

, pr ospective a djustments 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 20 1 3 and 201 2 were not material to the Authority’s overall operating revenue.

In September 2009, the Authority and Central entered into an agreem ent which, among other things, would permit Central to purchase the electric power and energy requirements necessary to serve five of its member cooperatives lo cated 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 Cooperat ive, Inc. (th e 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 Cen tral 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 e ffective

date , including V. C. Summer Units 2 and 3.



# N OTE 10

– C

OMMITMENTS AND CONTINGENCIES :

B udget

– 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 t he 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 es timated project cost is $5,047.6 million. (2) Will be financed by interna lly generated funds, taxable and tax

- exempt debt.I

- 28



### Purchase Commitments

- The Authority has contracted for l ong

- term coal purchase s under contracts with estimated outstanding minimum obligations after December 31, 201 3 . The disclosu re of minimum oblig ations (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,

Wi th 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 ou tstanding o bligation s under existing long

- term purchased power contract s as of December 31, 20 1 3 :

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 Obliga tions

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 o f 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 Corp oration and S CE&G for n etwork

i ntegration t ransmission s ervice to the Authority. The agreements are for network transmission service for the Upstate Load as defined in Note 9

– C ontracts with E lectric P ower C ooperatives . A payment schedule for these

agree ments shows that $ 8. 4 million will be due in 201 4 , with remaining annual payments totaling $ 21.4 million

thr ough the end of the contract term in 2023. However, a ma jority of the Upstate Load will transition to a new suppl ier as stated in N ote 9 and the Au thority’s obligation for transmission service for this load will decrease in approximately the same p roportion. At the end of the transition period, the Authority shall no longer be responsible for purchasing transmission service for the load served by th e 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 move ment 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 h as commitments for nuclear fuel, nuclear fuel conversion, enrichment and fabrication contracts for

V.C. Summer Units 1, 2 and 3

. As of December 31, 20 1 3 , these contracts total approximately $ 490.4 million over

the next 2 1 years.

In 20 10 , the Authority amended the Rainey Generating Station Lo ng

- Term Parts and Long

- Term Service Contract

with General Electri c 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 diagno stics of the turbine generator s and combustion tuning for the gas turbines.

The amended contract value is approximately $ 97.2 million, exc luding 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 20 18 )

. Rainey 2A and 2B have reached the contract “performance end date.” The Authority’s estimated remaining commitment o n the contract is $47.2 million and t he Authority is currently exploring options

for these units , incl uding a potential extension of t he GEII contract

. The contract can be terminated for

c onvenience 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 N ovember 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 interruptio n; and errors and omissions. The Authority purchases commercial

insurance to cover th ese risks, subject to coverage limits and various exclusions. Settled claims resulting from

these risks did not exceed commercial insurance coverage in 201 3

. Policies are subject to deductibles ranging from $ 500 to $ 2 .0 million, with the exception of nam ed 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 20 1 3 , 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

ex clusions, to cover automotive exposure in exces s 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 inf orm ation valued as of June 30, 2013

. In addition, t here hav e been no third

- party claims regarding environmental damages for 20 1 3 or 201 2

.I

- 30

Claim expenditures and liabilities are reported when it is probable that a loss has occurred and the amount o f the

l oss 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 prem iums 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 pol icy and be nefit program limits. T he State a ssumes all risks for the following: (1) claims of covered employees for health benefits covered through South Carolina Publ ic Employee Benefit Authority ( PEBA); not applicable for worker’s compensation injuries; and (2) c laims 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 plan s

. However, additional group life and long

term disability premiums are r emitted 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 fro m any nuclear incident has been established at $ 13.6 billion by the Pric e

- Anderson Indemnification Act. This $ 13

. 6 billion would be covered by nuclear liability insurance of $3 75 .0 million per reactor unit , with potential retrospective assessments of up t o $ 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 m illion per incident, per year). Based on its one

- third interest in V.C. Summer Nuclear

Unit 1 , the Authority coul d 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 addit ion al 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. 2 5 billion excess property and decontamination insurance to cover the costs of cleanup of the

facili ty in the event of an accident. SCE&G and the Authority also maintain accidental outage insurance to cover replacement power costs (within policy limits) a ssociated with an insured property loss. In addition to the premiums paid on the se three p olicies, 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 gener ating 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. 7 5 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. Base d on the Authority’s current 45 percent ownership interest, the Auth ority’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, clai ms 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, 20 1 3

.



### 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, t he 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 Au gust 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 v acated federal Clean Air M ercury 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 coll aborate 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 Authori ty 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

as sociated 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 em issions reductio ns over the period ending

2013. Capital costs have been offset by a reduced need to purchase emission credits. All emission s 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) Tailorin g 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 b oth regulatory and legislative efforts to reduce greenhouse gas emissions to ass ess potential impacts to its operations.

Through the maximum achievable control technology (MACT) regulatory process, the EPA has proposed the Utility MACT regulations to red uce 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 me rcury 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 not ice comment period. The Authority submitted comments to the proposed ru le

. 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

becam e 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 uni ts. 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.

T he Autho rity submitted comments to EPA by the January 7, 2013 deadline, and EPA complete d the updated rule

in March 2013 . The c ompliance date for new power plants remained set for July 16, 2015. In June 2013, EPA reopened the public comment period on reconsidera tion of startup and shutdown provisions. The Authority submitted comments to EPA. EPA intends to complete this portion of reconsideration sometime in 201 4

. 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, g enerating 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 r egional w ater p lant s are governed by NPDES permits issued by DHEC

. Further, the storm water from the generating stati ons 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

constructio n 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 o f 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 wastewa ter 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 Se ction 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 g enerating stations, substations and auxiliary facilities, maintain SPCC plans to meet certain standards. The Authority continually works to be in compliance with these regulations.

DHEC promulgate d a regulation effective June 2012 which requires permitting the withdrawal and use of surface

water. Although existing withdrawers , including the Aut hority’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 Envir onmental 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, stor ing and disposing of polychlorinated b i phenyls (PCB s ) 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

bec ome 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 haz ards 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 impos ed in the future for past waste disposal or compliance with new regulatory requirements. The A uthority 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 ha s 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 enter ed 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 give s EPA authority to regulate Underground Storage Tanks (US Ts). 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, operat ion, 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

– T he Authority follows GASB 49 which addresses s tandards for pollution (including contamination) remediation obligations for activities such as site assessments and cleanups.

GASB 49 does not include standards for pol lu tion remediation obligatio ns 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 clos ure 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,

201 3 and 201 2

. The method used to estimate the liabilities consists of weighting a range of possible estimated job cost amounts and calcul ating a weighted average cost. The weights and estimated costs are developed using professional engineering judgment acquired through years of estimating and completing many p ollution remediation projects.



### Homeland Secur

ity

– The Department o f 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 i ts 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

t hat has occurred since the U.S. Army Corps of Engineers’ (Corps) Cooper River Rediversion Project wa s 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 th e 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 t he 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 additio n, 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 Circui t. 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.I

- 34

In June 2012

, several environmental advocacy groups filed suit against the Authorit y 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 occu rred 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 a ny 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 ind emnification 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 re commendations. 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 r ecommendation 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 :

Substa ntially 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 Caro lina Code of Laws.

The payroll for active employees cove red 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) w ho retire at age 65 or with 28 years of service at any age are entitled

to a retirement ben efit, 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 ag e 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 compe nsation 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 provi des death and disability benefits. Benefits are established by State statute.

E ffective 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 cre dit or disability retirement benefits. Effective July 1, 2005, TERI employees began “re

contributing” to the SCRS at the prevailing rate. However, no service credit is ea rned under the new regulations. The group life insurance of one times annual salary w as 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 effect ive 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, regardle ss 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

req uirements 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). T he Authority contribute d 10.45 percent of the total pay roll for SCRS retirement . For 2013, the Authority also contributed an additional 0.15 percent of total payroll for group life. The contribution requirement s 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 finan cial 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 reti rement p lan 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 w hich is a defined benefit plan. The contribution amounts are the same, ( 7.50 percent employee

cost and 10.45 percent employer cost) ; however, 5 .0 0 percent of the employer amount is directed to the vendor chosen by the employee and the remaining 5.45 perc ent is to the Retirement System. As of December 31, 20 1 3

, t he Authority had 36 employees participati ng 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 es tablished 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 plan s 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 w ith 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 5.4I

- 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 pensi on 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, 20 1 3 and 20 1 2 , 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 F ASB ASC

715

. T he balances were ap p roximately $ 15.0 million and $ 30.2 million for the unfunded portion of pension

benefi ts at December 31, 20 1 3 and 201 2 , respectively. A dditional 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, 20 1 3

.



# NOTE 12

– OTHER POSTEMPLOYME NT BENEFITS (OPEB) :

Vacation / Sick Leave

– Full

- time e mployees earn 10 days of vaca tion leave for service under five years and 15 days of vacation leave for service under 11 years. E mployees earn an additional day of vacation leave for each year of serv ice over 10 until they reach t he 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 le ave and 180 days of sick leave. Upon termina tion, 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 partici pates in an agent multiple

- employer defined bene fit 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 substan tially 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 wit h at least 20 years of service. Currently, approximately 734 retirees meet these requirem ents.

For employees hired May 2, 2008 or thereafter, the number of years of earned service necessary to quali f y for funded retiree insurance is 15 years for a one

- half contribution, and 25 years for a full contribution. PEBA may be

contacte d at: Retire ment Benefits , PO Box 1166 0 , Columbia, S.C. 29211

- 1960

.



### Funding Policy

- Prior to 2010 , t he 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 ye ar $ 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, 201 3 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



### Fu nded Status and Funding Progress

- The funded status of the Authority’s retiree health care plan under
GASB 45 as of December 31, 201 2 , the latest actuarial study date, is as follows:

Required Supplementary Inform ation

- 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 progres s 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 Assump tions

- 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 payment s 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 por tion 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 contribu tions 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 th e 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

assu mptions 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

Investme nt 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

- T h e Authority is responsible for funding its share of OPEB cos ts for nuclear station employees. The Authority’s liability balances as of December 31, 20 1 3 and 201 2 were approximately $ 10.1 million and $ 9.5 million, respectively.

In accordance with FASB ASC 715, the Authority had recorded a regulatory asset and liabilit y of approximately $ 2.6 million and $ 5.3 million for the unfunded portion of OPEB c osts a t December 31, 201 3 and 201 2

, 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, 20 1 3

.



# NOTE 1 3

- C REDIT R

ISK AND M AJOR C USTOMERS

:

In 201 3 , the Authority had one customer that accounted for more than 10 p ercent 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 Dece mber 31, 201 3 and 201 2 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 , 201 4

, the date the financial statements were available for issu ance, 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 U nits 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 an d the Authority, 40 percent. Under the existing ownership agreement, SCE&G owns 55 percent and the A uthority owns 45 percent. The five percent ownership interest wo uld be acquired in three stages: (1) one percent at the commercial operation dat e 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 n o later than the second anniversary date of such commercial operation date.

The Agree ment 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.[THIS PAGE INTENTIONALLY LEFT BLANK]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 ther ein for any project, together with incidental costs (including legal, administrative, engineering, consulting and technical serv ices, 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 othe r 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 acquis ition of any other property (tangible or intangible), capital improvem ents or additions, or interests therei n, 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 cost s specified above, includi ng capitalized interest on such indebtedness, or (b) any indebtedness issued by the Authority to refund any indebtedness descri bed 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 follo wing 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 owners hip 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 Re serve Bank of New York th at 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 FederalII-2 Deposit Insurance Corporation, shall be secured by obliga tions described in clauses (2), (3), (4) or (7) of this paragraph, having a current market value (exclusive of accr ued interest) at least equal to one hundred five percent (105%) of the amount of such deposits, which obligations desc ribed 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 writte n 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, ra ted 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 pow er, operation, maintenance, generation, production, transmission, distribution, repairs, replacements, engineering, transportation, administration and general, audit, legal, financial, pension, retirement, health, hospitalizati on, 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 lim itations 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 refe rred 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 in to 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 wr iting 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 seni or 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 su bject to such Qualified Sw ap, or (ii) any such lowe r rating categories which each such Rating Agency indicates in writing to the Authority an d the Trustee will not, by itself, result in a reduction or withdrawal of its rating on th e 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, prof its, 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 paym ents 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 sh all 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 de rived 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 ot her 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, acqui red or leased in connectio n 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 provi ding 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 Oblig ation 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 cove rages, with insurance companies, and to carry liability insura nce 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 prescrib ed by its Board of Director s. 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 reve nues required by the Revenue Obligation Resolution to be paid into the Revenue Fund in the three immediately prec eding 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 m onthly 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 Und er 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 afte r 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 stat ed 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 institut e proceedings to be adjudicated a voluntary bankrupt, or shall consent to the filing of a bankruptcy proceeding ag ainst it, or shall file a petition or answer orII-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 appo intment 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 th e 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 Even ts 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 inco me 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 thereu nder (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 th e Trustee has refused or failed, within 60 days after the receipt of such request and after having been offered ad equate security and indemnity, to comply with such request. In the event the Trustee has failed or refuse d to comply with the afor esaid request, the Revenue Obligation Resolution provides for th e 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 c onsent 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 rede mption; 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 Obligatio ns 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 Re venue Obligations a ffected 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 paymen t 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, maturi ng as to principal and interest in su ch 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.[THIS PAGE INTENTIONALLY LEFT BLANK]134 MEETING STREET, THIRD FLOOR ( 29401-2240 )

POST OFFICE BOX 340 ( 29402-0340 )
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 Caroli na Public Service Authority Revenue Obligations,

2014 Series M1

We have acted as bond counsel and have exam ined a certified copy of the Transcript of Proceedings and other proofs submitted to us, in cluding 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, 2 014 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, Chapte r 31, Code of Laws of South Carolina 1976, as amended, and proceedings of th e Board of Directors of the Au thority 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 Ob ligation Resolution”). A ll capitalized terms used herein and not defined shall have the meaning as cribed to such terms in the Revenue Obligation

Resolution.

As to questions of fact material to our opi nion, we have relied upon representations of the Authority contained in the Reve nue Obligation Resolution and in the certified Transcript of Proceedings and other certifications of public officials and others fu rnished to us, without undertaking to verify the same by independent investigation.

Based upon the foregoing, we are of the opi nion, under existing statutes, regulations and
court decisions, as follows:

1. The 2014 M1 Bonds have been aut horized and issued in accordance with

the Constitution and statutes of the State of South Carolina and constitu te 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

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III - 2 other monies paid into the Revenue Fund (co llectively, 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 individua ls and corporations; it should be noted, however, that for the purpose of computi ng the alternative minimum tax imposed on certain corporations (as defined for federal inco me 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 Au thority comply with a ll requirements of the
Internal Revenue Code of 1986, as amended, that must be satisfied subsequent to the

issuance of the 2014 M1 Bond s in order that interest ther eon 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 re troactive to the date of issuance of the 2014 M1 Bonds. We express no opinion regarding other federal tax consequences arising with respect to th e 2014 M1 Bonds.

3. The 2014 M1 Bonds and the interest thereon are exempt from all state, county, school district, municipal, and all othe r taxes or assessments of the State of South Carolina, except inheritance, estate, tr ansfer or certain franchise taxes.

We express no opinion regardin g the accuracy, completeness, or sufficiency of any offering material relating to the 2014 M1 Bonds. Furthe rmore, 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 Bond s may be limited by bankruptcy , insolvency, reorganization,

moratorium and other similar laws affecting creditors' rights genera lly and by equitable principles, whether considered at law or in equity.

Very truly yours,