EX-13 20 ye13aepar.htm ANNUAL REPORT ye13aepar.htm
 
2013 Annual Reports

American Electric Power Company, Inc. and Subsidiary Companies
Appalachian Power Company and Subsidiaries
Indiana Michigan Power Company and Subsidiaries
Ohio Power Company and Subsidiaries
Public Service Company of Oklahoma
Southwestern Electric Power Company Consolidated









Audited Financial Statements and
Management’s Discussion and Analysis of Financial Condition and Results of Operations












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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX OF ANNUAL REPORTS

   
Page
Number
Glossary of Terms
 
i
     
Forward-Looking Information
 
v
     
AEP Common Stock and Dividend Information
 
vii
       
American Electric Power Company, Inc. and Subsidiary Companies:
   
 
Selected Consolidated Financial Data
 
1
 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
2
 
Reports of Independent Registered Public Accounting Firm
 
51
 
Management's Report on Internal Control Over Financial Reporting
 
53
 
Consolidated Financial Statements
 
54
 
Index of Notes to Consolidated Financial Statements
 
60
       
Appalachian Power Company and Subsidiaries:
   
 
Management’s Narrative Discussion and Analysis of Results of Operations
    152
 
Report of Independent Registered Public Accounting Firm
    158
 
Management's Report on Internal Control Over Financial Reporting
    159
 
Consolidated Financial Statements
    160
 
Index of Notes to Financial Statements of Registrant Subsidiaries
    166
       
Indiana Michigan Power Company and Subsidiaries:
   
 
Management’s Narrative Discussion and Analysis of Results of Operations
    168
 
Report of Independent Registered Public Accounting Firm
    174
 
Management's Report on Internal Control Over Financial Reporting
    175
 
Consolidated Financial Statements
    176
 
Index of Notes to Financial Statements of Registrant Subsidiaries
    182
       
Ohio Power Company and Subsidiaries:
   
 
Management’s Narrative Discussion and Analysis of Results of Operations
    184
 
Report of Independent Registered Public Accounting Firm
    190
 
Management's Report on Internal Control Over Financial Reporting
    191
 
Consolidated Financial Statements
    192
 
Index of Notes to Financial Statements of Registrant Subsidiaries
    198
       
Public Service Company of Oklahoma:
   
 
Management’s Narrative Discussion and Analysis of Results of Operations
    200
 
Report of Independent Registered Public Accounting Firm
    203
 
Management's Report on Internal Control Over Financial Reporting
    204
 
Financial Statements
    205
 
Index of Notes to Financial Statements of Registrant Subsidiaries
    211
       
Southwestern Electric Power Company Consolidated:
   
 
Management’s Narrative Discussion and Analysis of Results of Operations
    213
 
Report of Independent Registered Public Accounting Firm
    218
 
Management's Report on Internal Control Over Financial Reporting
    219
 
Consolidated Financial Statements
    220
 
Index of Notes to Financial Statements of Registrant Subsidiaries
    226
       
Index of Notes to Financial Statements of Registrant Subsidiaries
    227
       
Combined Management’s Narrative Discussion and Analysis of Registrant Subsidiaries
    376

 
 

 

GLOSSARY OF TERMS
 
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

Term
 
Meaning
     
AEGCo
 
AEP Generating Company, an AEP electric utility subsidiary.
AEP or Parent
 
American Electric Power Company, Inc., an electric utility holding company.
AEP Consolidated
 
AEP and its majority owned consolidated subsidiaries and consolidated affiliates.
AEP Credit
 
AEP Credit, Inc., a consolidated variable interest entity of AEP which securitizes accounts receivable and accrued utility revenues for affiliated electric utility companies.
AEP East Companies
 
APCo, I&M, KPCo and OPCo.
AEP Energy
 
AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.  BlueStar began doing business as AEP Energy, Inc. in June 2012.
AEP System
 
American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP Transmission Holdco
 
AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.
AEP West Companies
 
PSO, SWEPCo, TCC and TNC.
AEPEP
 
AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, asset management and commercial and industrial sales in the deregulated Texas market.
AEPES
 
AEP Energy Services, Inc., a subsidiary of AEP Resources, Inc.
AEPSC
 
American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.
AFUDC
 
Allowance for Funds Used During Construction.
AGR
 
AEP Generation Resources Inc., a nonregulated AEP subsidiary that acquired the generation assets and liabilities of OPCo.
AOCI
 
Accumulated Other Comprehensive Income.
APCo
 
Appalachian Power Company, an AEP electric utility subsidiary.
APSC
 
Arkansas Public Service Commission.
Appalachian Consumer Rate Relief Funding
 
Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to the under-recovered ENEC deferral balance.
BlueStar
 
BlueStar Energy Holdings, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and other deregulated electricity markets throughout the United States.  BlueStar began doing business as AEP Energy, Inc. in June 2012.
BOA
 
Bank of America Corporation.
CAA
 
Clean Air Act.
CLECO
 
Central Louisiana Electric Company, a nonaffiliated utility company.
CO2
 
Carbon dioxide and other greenhouse gases.
Cook Plant
 
Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M.
CRES provider
 
Competitive Retail Electric Service providers under Ohio law that target retail customers by offering alternative generation service.
CSPCo
 
Columbus Southern Power Company, a former AEP electric utility subsidiary that was merged into OPCo effective December 31, 2011.
CWIP
 
Construction Work in Progress.
 
 
i

 
Term   Meaning
     
DCC Fuel
 
DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, DCC Fuel IV LLC, DCC Fuel V LLC and DCC Fuel VI LLC, consolidated variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M.
DHLC
 
Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.
E&R
 
Environmental compliance and transmission and distribution system reliability.
EIS
 
Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated variable interest entity of AEP.
ENEC
 
Expanded Net Energy Charge.
ERCOT
 
Electric Reliability Council of Texas regional transmission organization.
ESP
 
Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with the PUCO.
ETT
 
Electric Transmission Texas, LLC, an equity interest joint venture between AEP and MidAmerican Energy Holdings Company Texas Transco, LLC formed to own and operate electric transmission facilities in ERCOT.
FAC
 
Fuel Adjustment Clause.
FASB
 
Financial Accounting Standards Board.
Federal EPA
 
United States Environmental Protection Agency.
FERC
 
Federal Energy Regulatory Commission.
FGD
 
Flue Gas Desulfurization or scrubbers.
FTR
 
Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.
GAAP
 
Accounting Principles Generally Accepted in the United States of America.
I&M
 
Indiana Michigan Power Company, an AEP electric utility subsidiary.
IEU
 
Industrial Energy Users-Ohio.
IGCC
 
Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
Interconnection Agreement
 
An agreement by and among APCo, I&M, KPCo and OPCo which defined the sharing of costs and benefits associated with their respective generation plants.  This agreement was terminated January 1, 2014.
IRS
 
Internal Revenue Service.
IURC
 
Indiana Utility Regulatory Commission.
KGPCo
 
Kingsport Power Company, an AEP electric utility subsidiary.
KPCo
 
Kentucky Power Company, an AEP electric utility subsidiary.
KPSC
 
Kentucky Public Service Commission.
kV
 
Kilovolt.
KWh
 
Kilowatthour.
LPSC
 
Louisiana Public Service Commission.
MISO
 
Midwest Independent Transmission System Operator.
MLR
 
Member load ratio, the method used to allocate transactions among members of the Interconnection Agreement.
MMBtu
 
Million British Thermal Units.
MPSC
 
Michigan Public Service Commission.
MTM
 
Mark-to-Market.
MW
 
Megawatt.
MWh
 
Megawatthour.
NOx
 
Nitrogen oxide.
Nonutility Money Pool
 
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain nonutility subsidiaries.
 
 
ii

 
Term   Meaning
     
NSR
 
New Source Review.
OATT
 
Open Access Transmission Tariff.
OCC
 
Corporation Commission of the State of Oklahoma.
Ohio Phase-in-Recovery Funding
 
Ohio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo and a consolidated variable interest entity formed for the purpose of issuing and servicing securitization bonds related to phase-in recovery property.
OPCo
 
Ohio Power Company, an AEP electric utility subsidiary.
OPEB
 
Other Postretirement Benefit Plans.
Operating Agreement
 
Agreement, dated January 1, 1997, as amended, by and among PSO and SWEPCo governing generating capacity allocation, energy pricing, and revenues and costs of third party sales.  AEPSC acts as the agent.
OTC
 
Over the counter.
OVEC
 
Ohio Valley Electric Corporation, which is 43.47% owned by AEP.
PCA
 
Power Coordination Agreement among APCo, I&M and KPCo.
PJM
 
Pennsylvania – New Jersey – Maryland regional transmission organization.
PM
 
Particulate Matter.
POLR
 
Provider of Last Resort revenues.
PSO
 
Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO
 
Public Utilities Commission of Ohio.
PUCT
 
Public Utility Commission of Texas.
Registrant Subsidiaries
 
AEP subsidiaries which are SEC registrants; APCo, I&M, OPCo, PSO and SWEPCo.
Risk Management Contracts
 
Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant
 
A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport, Indiana.  AEGCo and I&M jointly-own Unit 1.  In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidated trustee for Rockport Plant, Unit 2.
RTO
 
Regional Transmission Organization, responsible for moving electricity over large interstate areas.
Sabine
 
Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity for AEP and SWEPCo.
SEC
 
U.S. Securities and Exchange Commission.
SEET
 
Significantly Excessive Earnings Test.
SIA
 
System Integration Agreement, effective June 15, 2000, provides contractual basis for coordinated planning, operation and maintenance of the power supply sources of the combined AEP.
SNF
 
Spent Nuclear Fuel.
SO2
 
Sulfur dioxide.
SPP
 
Southwest Power Pool regional transmission organization.
SSO
 
Standard service offer.
Stall Unit
 
J. Lamar Stall Unit at Arsenal Hill Plant, a 534 MW natural gas unit owned by SWEPCo.
SWEPCo
 
Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC
 
AEP Texas Central Company, an AEP electric utility subsidiary.
Texas Restructuring Legislation
 
Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC
 
AEP Texas North Company, an AEP electric utility subsidiary.
 
 
iii

 
Term   Meaning
     
Transition Funding
 
AEP Texas Central Transition Funding I LLC, AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas restructuring law.
True-up Proceeding
 
A filing made under the Texas Restructuring Legislation to finalize the amount of stranded costs and other true-up items and the recovery of such amounts.
Turk Plant
 
John W. Turk, Jr. Plant, a 600 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.
Utility Money Pool
 
Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.
VIE
 
Variable Interest Entity.
Virginia SCC
 
Virginia State Corporation Commission.
WPCo
 
Wheeling Power Company, an AEP electric utility subsidiary.
WVPSC
 
Public Service Commission of West Virginia.

 
iv

 

FORWARD-LOOKING INFORMATION

This report made by AEP and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934.  Many forward-looking statements appear in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations,” but there are others throughout this document which may be identified by words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook.  These matters are subject to risks and uncertainties that could cause actual results to differ materially from those projected.  Forward-looking statements in this document are presented as of the date of this document.  Except to the extent required by applicable law, we undertake no obligation to update or revise any forward-looking statement.  Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

·
The economic climate, growth or contraction within and changes in market demand and demographic patterns in our service territory.
·
Inflationary or deflationary interest rate trends.
·
Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates.
·
The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material.
·
Electric load, customer growth and the impact of retail competition, particularly in Ohio.
·
Weather conditions, including storms and drought conditions, and our ability to recover significant storm restoration costs through applicable rate mechanisms.
·
Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
·
Availability of necessary generation capacity and the performance of our generation plants.
·
Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·
Our ability to build or acquire generation capacity and transmission lines and facilities (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of projects that are cancelled) through applicable rate cases or competitive rates.
·
New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation, cost recovery and/or profitability of our generation plants and related assets.
·
Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
·
A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers.
·
Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance.
·
Resolution of litigation.
·
Our ability to constrain operation and maintenance costs.
·
Our ability to develop and execute a strategy based on a view regarding prices of electricity and other energy-related commodities.
·
Prices and demand for power that we generate and sell at wholesale.
·
Changes in technology, particularly with respect to new, developing or alternative sources of generation.
·
Our ability to recover through rates or market prices any remaining unrecovered investment in generation units that may be retired before the end of their previously projected useful lives.
·
Volatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas.
 
 
v

 
·
Changes in utility regulation and the allocation of costs within regional transmission organizations, including PJM and SPP.
·
The transition to market generation in Ohio, including the implementation of ESPs.
·
Our ability to successfully and profitably manage our Ohio generation assets in a startup, nonregulated merchant business.
·
Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
·
Actions of rating agencies, including changes in the ratings of our debt.
·
The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans, captive insurance entity and nuclear decommissioning trust and the impact on future funding requirements.
·
Accounting pronouncements periodically issued by accounting standard-setting bodies.
·
Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events.
 
The forward looking statements of AEP and its Registrant Subsidiaries speak only as of the date of this report or as of the date they are made.  AEP and its Registrant Subsidiaries expressly disclaim any obligation to update any forward-looking information.  For a more detailed discussion of these factors, see “Risk Factors” in Part I of this report.

 
vi

 
AEP COMMON STOCK AND DIVIDEND INFORMATION

The AEP common stock quarterly high and low sales prices, quarter-end closing price and the cash dividends paid per share are shown in the following table:

 
 
 
 
 
 
 
 
Quarter-End
 
 
 
Quarter Ended
 
High
 
Low
 
Closing Price
 
Dividend
December 31, 2013
 
$
 48.40 
 
$
 43.01 
 
$
 46.74 
 
$
 0.50 
September 30, 2013
 
 
 47.59 
 
 
 41.83 
 
 
 43.35 
 
 
 0.49 
June 30, 2013
 
 
 51.60 
 
 
 42.83 
 
 
 44.78 
 
 
 0.49 
March 31, 2013
 
 
 48.68 
 
 
 42.92 
 
 
 48.63 
 
 
 0.47 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2012
 
$
 45.41 
 
$
 40.56 
 
$
 42.68 
 
$
 0.47 
September 30, 2012
 
 
 44.84 
 
 
 39.62 
 
 
 43.94 
 
 
 0.47 
June 30, 2012
 
 
 40.46 
 
 
 36.97 
 
 
 39.90 
 
 
 0.47 
March 31, 2012
 
 
 41.98 
 
 
 37.46 
 
 
 38.58 
 
 
 0.47 

AEP common stock is traded principally on the New York Stock Exchange.  As of December 31, 2013, AEP had approximately 78,000 registered shareholders.
 
5 Year Cumulative Total Return
 
 
vii

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
2013 
 
2012 
 
2011 
 
2010 
 
2009 
 
 
 
(dollars in millions, except per share amounts)
STATEMENTS OF INCOME DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Revenues
$
 15,357 
 
$
 14,945 
 
$
 15,116 
 
$
 14,427 
 
$
 13,489 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating Income
$
 2,855 
 
$
 2,656 
 
$
 2,782 
 
$
 2,663 
 
$
 2,771 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Before Extraordinary Items
$
 1,484 
 
$
 1,262 
 
$
 1,576 
 
$
 1,218 
 
$
 1,370 
Extraordinary Items, Net of Tax
 
 - 
 
 
 - 
 
 
 373 
 
 
 - 
 
 
 (5)
Net Income
 
 1,484 
 
 
 1,262 
 
 
 1,949 
 
 
 1,218 
 
 
 1,365 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income Attributable to Noncontrolling Interests
 
 4 
 
 
 3 
 
 
 3 
 
 
 4 
 
 
 5 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS
 
 1,480 
 
 
 1,259 
 
 
 1,946 
 
 
 1,214 
 
 
 1,360 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Preferred Stock Dividend Requirements of Subsidiaries Including
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Capital Stock Expense
 
 - 
 
 
 - 
 
 
 5 
 
 
 3 
 
 
 3 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
$
 1,480 
 
$
 1,259 
 
$
 1,941 
 
$
 1,211 
 
$
 1,357 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
BALANCE SHEETS DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Property, Plant and Equipment
$
 60,285 
 
$
 57,454 
 
$
 55,670 
 
$
 53,740 
 
$
 51,684 
Accumulated Depreciation and Amortization
 
 19,288 
 
 
 18,691 
 
 
 18,699 
 
 
 18,066 
 
 
 17,340 
Total Property, Plant and Equipment – Net
$
 40,997 
 
$
 38,763 
 
$
 36,971 
 
$
 35,674 
 
$
 34,344 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Assets
$
 56,414 
 
$
 54,367 
 
$
 52,223 
 
$
 50,455 
 
$
 48,348 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total AEP Common Shareholders’ Equity
$
 16,085 
 
$
 15,237 
 
$
 14,664 
 
$
 13,622 
 
$
 13,140 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Noncontrolling Interests
$
 1 
 
$
 - 
 
$
 1 
 
$
 - 
 
$
 - 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
$
 - 
 
$
 - 
 
$
 - 
 
$
 60 
 
$
 61 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-term Debt (a)
$
 18,377 
 
$
 17,757 
 
$
 16,516 
 
$
 16,811 
 
$
 17,498 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Obligations Under Capital Leases (a)
$
 538 
 
$
 449 
 
$
 458 
 
$
 474 
(b)
$
 317 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
AEP COMMON STOCK DATA
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Income Before Extraordinary Items
$
 3.04 
 
$
 2.60 
 
$
 3.25 
 
$
 2.53 
 
$
 2.97 
Extraordinary Items, Net of Tax
 
 - 
 
 
 - 
 
 
 0.77 
 
 
 - 
 
 
 (0.01) 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Total Basic Earnings per Share Attributable to AEP Common Shareholders
$
 3.04 
 
$
 2.60 
 
$
 4.02 
 
$
 2.53 
 
$
 2.96 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Weighted Average Number of Basic Shares Outstanding (in millions)
 
 487 
 
 
 485 
 
 
 482 
 
 
 479 
 
 
 459 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Market Price Range:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
High
$
 51.60 
 
$
 45.41 
 
$
 41.71 
 
$
 37.94 
 
$
 36.51 
 
 
Low
$
 41.83 
 
$
 36.97 
 
$
 33.09 
 
$
 28.17 
 
$
 24.00 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Year-end Market Price
$
 46.74 
 
$
 42.68 
 
$
 41.31 
 
$
 35.98 
 
$
 34.79 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Dividends Declared per AEP Common Share
$
 1.95 
 
$
 1.88 
 
$
 1.85 
 
$
 1.71 
 
$
 1.64 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Dividend Payout Ratio
 
64.14%
 
 
72.31%
 
 
46.02%
 
 
67.59%
 
 
55.41%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Book Value per AEP Common Share
$
 32.98 
 
$
 31.35 
 
$
 30.36 
 
$
 28.32 
 
$
 27.49 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a)
Includes portion due within one year.
(b)
Obligations Under Capital Leases increased primarily due to capital leases under new master lease agreements for property that was previously leased
 
 
under operating leases.
 
 
 
 
 
 
 
 
 
 
 
 
 
 

 
1

 

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

American Electric Power Company, Inc. (AEP) is one of the largest investor-owned electric public utility holding companies in the United States.  Our electric utility operating companies provide generation, transmission and distribution services to more than five million retail customers in Arkansas, Indiana, Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia.

Our subsidiaries operate an extensive portfolio of assets including:

·
Approximately 37,600 megawatts of generating capacity, one of the largest complements of generation in the United States.
·
More than 40,000 miles of transmission lines, including 2,110 miles of 765kV lines, the backbone of the electric interconnection grid in the Eastern United States.
·
Approximately 222,000 miles of distribution lines that deliver electricity to 5.3 million customers.
·
Substantial commodity transportation assets (more than 5,700 railcars, approximately 3,000 barges, 60 towboats, 25 harbor boats and a coal handling terminal with approximately 18 million tons of annual capacity).  Our commercial barging operations annually transport approximately 37 million tons of coal and dry bulk commodities.  Approximately 39% of the barging is for transportation of agricultural products, 26% for coal, 20% for steel and 15% for other commodities.

Corporate Separation

Background

On December 31, 2013, based on FERC and PUCO orders which approved corporate separation of generation assets and associated liabilities, OPCo transferred its generation assets and related generation liabilities at net book value to AGR.  In accordance with Ohio law, OPCo remains responsible to provide power and capacity to OPCo customers who have not switched electric providers.  Effective January 1, 2014, OPCo will purchase power from both affiliated and nonaffiliated entities, subject to PUCO approval, to meet the energy and capacity needs of customers.

On December 31, 2013, subsequent to the transfer of OPCo’s generation assets and associated liabilities to AGR, AGR transferred at net book value its ownership (867 MW) in Amos Plant, Unit 3 to APCo.  The transfer of these generation assets and associated liabilities was approved by the FERC, the Virginia SCC and the WVPSC.

On December 31, 2013, subsequent to the transfer of OPCo’s generation assets and associated liabilities to AGR, AGR transferred at net book value a one-half interest (780 MW) in the Mitchell Plant to KPCo.  The transfer of these generation assets and associated liabilities was approved by the FERC and the KPSC.

Other Impacts of Corporate Separation

In accordance with our December 2010 announcement and our October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014.  The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO2 emission allowances associated with transactions under the Interconnection Agreement was also terminated.

Effective January 1, 2014, the FERC approved the following:

·  
Power Coordination Agreement among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources.
·  
Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent to address open commitments related to the termination of the Interconnection Agreement and responsibilities to PJM.
·  
Power Supply Agreement between AGR and OPCo for AGR to supply capacity for OPCo’s switched and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that is not acquired through auctions from January 1, 2014 through December 31, 2014.

 
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For a further discussion of corporate separation, see the “Corporate Separation” section of Note 1 and the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters in Note 4.

Ohio Electric Security Plan Filings

2009 – 2011 ESP

In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover OPCo’s deferred fuel costs in rates beginning September 2012.  As of December 31, 2013, OPCo’s net deferred fuel balance was $445 million, excluding unrecognized equity carrying costs.  Decisions from the Supreme Court of Ohio are pending related to various appeals which, if ordered, could reduce OPCo’s net deferred fuel costs balance.
 
June 2012 – May 2015 Ohio ESP Including Capacity Charge
 
In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015.  This ruling was generally upheld in PUCO rehearing orders in January and March 2013.

In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day.  The RPM price is approximately $33/MW day through May 2014 and $148/MW day from June 2014 through May 2015.  In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.

As part of the August 2012 ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012.  The RSR is being collected from customers at $3.50/MWh through May 2014 and will be collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs.  In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order, including the RSR.  As of December 31, 2013, OPCo’s incurred deferred capacity costs balance was $288 million, including debt carrying costs.

In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications.  The modifications include the delay of the energy auctions that were originally ordered in the ESP order.  OPCo must conduct an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015.  The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning November 2014 through May 2015 and for the remaining 40% of the SSO load for delivery from January 2015 through May 2015.  OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015.  The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned.  Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings.  Management believes that these intervenor concerns are without merit.  In December 2013, the PUCO granted applications for rehearing for further consideration filed by OPCo and intervenors.  In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012-2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC.

Proposed June 2015 – May 2018 ESP

In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders effective June 2015 through May 2018.  This filing is consistent with the PUCO’s objective for a full transition from FAC and base generation rates to market.  The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation through OPCo.  Additionally, the application identifies OPCo’s intention to submit a separate application to continue the RSR established in the June 2012 – May 2015 ESP in which the unrecovered portion of the deferred capacity costs will continue to be collected at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected.  Management intends to file this application in the first quarter of 2014.
 
 
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If OPCo is ultimately not permitted to fully collect its ESP rates including the RSR, and its deferred capacity costs, it could reduce future net income and cash flows and impact financial condition.  See “Ohio Electric Security Plan Filing” section of Note 4.

Ohio Customer Choice

In our Ohio service territory, various CRES providers are targeting retail customers by offering alternative generation service.  The reduction in gross margin as a result of customer switching in Ohio is partially offset by (a) collection of capacity revenues from CRES providers, (b) off-system sales, (c) deferral of unrecovered capacity costs, (d) RSR collections and (e) revenues from AEP Energy.  AEP Energy is our CRES provider and part of our Generation & Marketing segment which targets retail customers, both within and outside of our retail service territory.

Customer Demand

In comparison to 2012, our weather-normalized retail sales decreased 1.6% for the year ended December 31, 2013.  Our industrial sales declined 4.5% partially due to lower production levels at Ormet, a large aluminum company.  Ormet had a contract to purchase power from OPCo through 2018.  In October 2013, Ormet announced that it was unable to emerge from bankruptcy and shut down its operations effective immediately.  The loss of Ormet's load will not have a material impact on future gross margin.  Power previously sold to Ormet will be available to be sold into wholesale markets.

In 2014, we anticipate weather-normalized retail sales will decline by 1.1%.  Excluding Ormet, total weather-normalized retail sales are projected to increase by 0.1% in 2014.  The largest decline is projected to occur in the industrial class, principally due to Ormet’s decision to shut down.  Excluding Ormet, the industrial class is projected to grow by 1.2% in 2014, primarily related to a number of new oil and natural gas expansions, especially around the major shale gas areas within AEP's footprint.  Weather-normalized residential sales are projected to decline by 0.9% in 2014, continuing the recent trend of declining use per customer related to higher saturations of energy efficient appliances and the promotion of utility sponsored energy efficiency programs.  The commercial class energy sales are projected to remain flat compared to 2013.

PJM Capacity Auction

AGR is required to offer all of its available generation in the PJM Reliability Pricing Model (RPM) auction, which is conducted three years in advance of the actual delivery year.  Therefore, the majority of AGR generation assets are subject to PJM capacity prices for periods after May 2015.  Through May 2015, AGR will provide generation capacity to OPCo for both switched and non-switched OPCo generation customers.  For switched customers, OPCo pays AGR $188.88/MW day.  For non-switched OPCo generation customers, OPCo pays AGR for capacity.  AGR’s non-OPCo load is subject to the PJM RPM auction.  Shown below are the current auction prices for capacity, as announced/settled by PJM:

 
 
PJM Base
PJM Auction Period
 
Auction Price
 
 
(per MW day) 
June 2013 through May 2014
 
$
 27.73 
June 2014 through May 2015
 
 
 125.99 
June 2015 through May 2016
 
 
 136.00 
June 2016 through May 2017
 
 
 59.37 

We formed a coalition with other utility companies to address mutual concerns related to the PJM capacity auction process, including: (a) import limits for power without firm transmission, (b) placing bidding caps on available demand response resources in comparison to base generation capacity, (c) modification and enforcement of the timing of demand response requirements to better reflect real-time capacity requirements and (d) tightened rules for incremental auctions in which speculative bidders sell resources in the base auction and buy back that capacity in an incremental auction, resulting in no additional capacity and lower market prices.  PJM has made three FERC filings related to the first three issues.  We anticipate that another filing will be made by PJM later in the first quarter of
 
 
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2014 to address the fourth issue.  In January 2014, FERC accepted without modification PJM's filed recommendations on placing bidding caps on certain demand response products that are available only during the summer period.  We expect to receive FERC decisions on the other filings prior to the next RPM auction in May 2014.

Turk Plant

SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012.  SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility.  As of December 31, 2013, SWEPCo’s share of incurred construction expenditures for the Turk Plant was approximately $1.758 billion.  As of December 31, 2013, a pretax provision of $59 million has been recorded for costs incurred in excess of a Texas cost cap, resulting in total net capitalized expenditures of $1.699 billion.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant.  In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN.  This Turk Plant output that is currently not subject to cost-based rate recovery and is being sold into the wholesale market.  If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant or transmission lines, it could reduce future net income and cash flows and impact financial condition.  See the “Turk Plant” section of Note 4.

2012 Texas Base Rate Case

In December 2013, the PUCT issued an order granting rehearing and reversed its decision on consolidated tax savings increasing SWEPCo’s annual revenues by $5 million.  In January 2014, the PUCT determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap.  As a result of these rulings, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances.  These rulings also increased SWEPCo’s previously approved annual base rates by a total of $13 million.  The resulting annual base rate increase is approximately $52 million.  See the “Turk Plant” and the “2012 Texas Base Rate Case” sections of Note 4.

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share of the Turk Plant.  In February 2013, a settlement was approved by the LPSC that increased Louisiana total rates by approximately $2 million annually, effective March 2013.  The March 2013 base rates are based upon a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund.  The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013.  In May 2013, SWEPCo filed testimony in the prudency review of the Turk Plant.  If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudency review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.  See the “2012 Louisiana Formula Rate Filing” section of Note 4.

Welsh Plant, Units 1 and 3 - Environmental Projects

To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet Mercury and Air Toxics Standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million, excluding AFUDC.  Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million, excluding AFUDC.  As of December 31, 2013, SWEPCo has incurred $32 million in costs related to these projects.  SWEPCo will seek recovery of costs it incurs from these projects from its state commissions and FERC customers.
 
 
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2011 Indiana Base Rate Case

In 2013, the IURC issued an order that granted a $92 million annual increase in base rates based upon a return on common equity of 10.2%.  In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal of the orders with the Indiana Court of Appeals.  In September 2013, the OUCC filed a brief on appeal that included objections to certain aspects of the rate case.  If any part of the IURC order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows.  See the “2011 Indiana Base Rate Case” section of Note 4.

2014 Oklahoma Base Rate Case

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity.  This revenue increase includes a proposed increase in depreciation rates of $29 million.  In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three.  The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional types of transmission costs that are expected to increase over the next several years.

Rockport Plant Clean Coal Technology Project (CCT Project)

In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both units of the Rockport Plant with a dry sorbent injection system.  The estimated cost in the application was $285 million, excluding AFUDC to be shared equally between I&M and AEGCo.  In November 2013, the IURC approved a settlement agreement that included the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M’s ownership share.  As of December 31, 2013, we have incurred costs of $109 million related to the CCT Project, including AFUDC.  See the “Rockport Plant Clean Coal Technology Project (CCT Project)” section of Note 4.

Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its licensed life (2034 for Unit 1 and 2037 for Unit 2).  The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC.  As of December 31, 2013, I&M has incurred costs of $380 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M’s proposed project with the exception of an estimated $23 million related to certain items which the IURC stated I&M could seek recovery of in a subsequent base rate case.  I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings.  The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates.  In October 2013, I&M filed an application with the IURC for LCM rider rates effective January 2014.  In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC.

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to the approved projects effective January 2013 until these costs are included in rates.  In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON.

If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.  See “Cook Plant Life Cycle Management Project (LCM Project)” section of Note 4.
 
 
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Repositioning Efforts

In April 2012, we initiated a process to identify strategic repositioning opportunities and efficiencies that resulted in sustainable cost savings.  This process included evaluations of our employee and retiree benefit programs as well as evaluations of the functional effectiveness and staffing levels of our finance and accounting, information technology, generation and supply chain and procurement organizations.  While we have completed certain aspects of this program, our continuous improvement initiatives in generation, distribution, transmission, supply chain, procurement and the corporate center continues to yield cost savings for many of our subsidiaries, allowing us to direct many of these savings into infrastructure and other areas of our business.

LITIGATION

In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation.  Since it is difficult to predict the outcome of these proceedings, we cannot predict the eventual resolution, timing or amount of any loss, fine or penalty.  We assess the probability of loss for each contingency and accrue a liability for cases that have a probable likelihood of loss if the loss can be estimated.  For details on our regulatory proceedings and pending litigation see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies.  Adverse results in these proceedings have the potential to reduce future net income and cash flows and impact financial condition.

Rockport Plant Litigation

In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022.  The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit.  The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement.  The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff.  The New York court has granted our motion to transfer this case to the U.S. District Court for the Southern District of Ohio.  Our motion to dismiss the case, filed in October 2013, is pending.  We will continue to defend against the claims.  We are unable to determine a range of potential losses that are reasonably possible of occurring.

ENVIRONMENTAL ISSUES

We are implementing a substantial capital investment program and incurring additional operational costs to comply with environmental control requirements.  We will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants (HAPs) from fossil fuel-fired power plants, proposals governing the beneficial use and disposal of coal combustion products and proposed clean water rules.
 
We are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of our nuclear units.  We, along with various industry groups, affected states and other parties have challenged some of the Federal EPA requirements in court.  We are also engaged in the development of possible future requirements including the items discussed below and reductions of CO2 emissions to address concerns about global climate change.  We believe that further analysis and better coordination of these environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmental goals.

We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions.  Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances.  If we are unable to recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.
 
 
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Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System.  We continue to evaluate the impact of these rules, project scope and technology available to achieve compliance.  As of December 31, 2013, the AEP System had a total generating capacity of nearly 37,600 MWs, of which over 23,700 MWs are coal-fired.  We continue to refine the cost estimates of complying with these rules and other impacts of the environmental proposals on our coal-fired generating facilities.  Based upon our estimates, investment to meet these proposed requirements ranges from approximately $3 billion to $3.5 billion between 2013 and 2020.  These amounts include investments to convert some of our coal generation to natural gas.  If natural gas conversion is not completed, these units could be retired sooner than planned.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules.  The cost estimates will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans or federal implementation plans that impose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on our units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.  In addition, we are continuing to evaluate the economic feasibility of environmental investments on nonregulated plants.

Subject to the factors listed above and based upon our continuing evaluation, we intend to retire the following plants or units of plants before or during 2016:

 
 
 
 
Generating
Company
 
Plant Name and Unit
 
Capacity
 
 
 
 
(in MWs) 
APCo
 
Clinch River Plant, Unit 3
 
 
 235 
APCo
 
Glen Lyn Plant
 
 
 335 
APCo
 
Kanawha River Plant
 
 
 400 
APCo/AGR
 
Sporn Plant, Units 1-4
 
 
 600 
I&M
 
Tanners Creek Plant, Units 1-4
 
 
 995 
KPCo
 
Big Sandy Plant, Unit 2
 
 
 800 
AGR
 
Kammer Plant
 
 
 630 
AGR
 
Muskingum River Plant, Units 1-5
 
 
 1,440 
AGR
 
Picway Plant
 
 
 100 
PSO
 
Northeastern Station, Unit 4
 
 
 470 
SWEPCo
 
Welsh Plant, Unit 2
 
 
 528 
Total
 
 
 
 
 6,533 

As of December 31, 2013, the net book value of the AGR units listed above was zero.  The net book value, before cost of removal, including related material and supplies inventory and CWIP balances of the other plants in the table above was $1 billion.  See Note 5 for further discussion.

In 2013, we re-evaluated potential courses of action with respect to the planned operation of Muskingum River Plant, Unit 5 and concluded that completion of a refueling project which would extend the unit’s useful life is remote.  As a result, in 2013, we completed an impairment analysis and recorded a $154 million pretax ($99 million, net of tax) impairment charge for AGR’s net book value of Muskingum River Plant, Unit 5.  We expect to retire the plant no later than 2015.  See “Muskingum River Plant, Unit 5” section of Note 7.
 
 
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In addition, we are in the process of obtaining permits and other necessary regulatory approvals for either the conversion of some of our coal units to natural gas or installing emission control equipment on certain units.  The following table lists the plants or units that are either awaiting regulatory approval or are still being evaluated by management based on changes in emission requirements and demand for power:

 
 
 
 
Generating
Company
 
Plant Name and Unit
 
Capacity
 
 
 
 
(in MWs) 
KPCo
 
Big Sandy Plant, Unit 1
 
 
 278 
PSO
 
Northeastern Station, Unit 3
 
 
 470 
Total
 
 
 
 
 748 

As of December 31, 2013, the net book value before cost of removal, including related material and supplies inventory and CWIP balances, of the plants in the table above was $295 million.

Volatility in natural gas prices, pending environmental rules and other market factors could also have an adverse impact on the accounting evaluation of the recoverability of the net book values of coal-fired units.  For regulated plants that we may close early, we are seeking regulatory recovery of remaining net book values.  To the extent existing generation assets and the cost of new equipment and converted facilities are not recoverable, it could materially reduce future net income and cash flows.

Modification of the NSR Litigation Consent Decree

In 2007, the U.S. District Court for the Southern District of Ohio approved a consent decree between the AEP subsidiaries in the eastern area of the AEP System and the Department of Justice, the Federal EPA, eight northeastern states and other interested parties to settle claims that the AEP subsidiaries violated the NSR provisions of the CAA when it undertook various equipment repair and replacement projects over a period of nearly 20 years.  The consent decree’s terms include installation of environmental control equipment on certain generating units, a declining cap on SO2 and NOx emissions from the AEP System and various mitigation projects.

The original consent decree required certain types of control equipment to be installed at Muskingum River Plant, Unit 5, Big Sandy Plant, Unit 2 and the two units of the Rockport Plant in 2015, 2017 and 2019, respectively.  In January 2013, an agreement to modify the consent decree was reached and filed with the court.  The terms of the agreement include more options for the affected units (including alternative control technologies, re-fueling and/or retirement), more stringent SO2 emission caps for the AEP System and additional mitigation measures.  The modified consent decree was approved by the court in May 2013.  For the units of the Rockport Plant, the modified decree requires installation of dry sorbent injection technology for SO2 control on both units in 2015.  In addition, the consent decree imposes a declining plant-wide cap on SO2 emissions beginning in 2016.

Oklahoma Environmental Compliance Plan

In September 2012, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES), Unit 4 in 2016 and additional environmental controls on NES, Unit 3 to continue operations through 2026.  As of December 31, 2013, the net book values of NES, Units 3 and 4 were $208 million and $106 million, respectively, before cost of removal, including materials and supplies inventory and CWIP.  In August 2013, the OCC dismissed PSO’s environmental compliance plan case without prejudice but will permit PSO to seek recovery in a future proceeding.  PSO will address the environmental compliance plan issues in future regulatory proceedings when it seeks cost recovery of the plan.  If PSO is ultimately not permitted to fully recover its net book value of NES, Units 3 and 4 and other environmental compliance costs, it could reduce future net income and cash flows and impact financial condition.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions.  The states implement and administer many of these programs and could impose additional or more stringent requirements.
 
 
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The Federal EPA issued the Clean Air Interstate Rule (CAIR) in 2005 requiring specific reductions in SO2 and NOx emissions from power plants.  In 2008, the District of Columbia Circuit Court of Appeals issued a decision remanding CAIR to the Federal EPA.  The Federal EPA issued the Cross-State Air Pollution Rule (CSAPR) (discussed in detail below) in August 2011 to replace CAIR.  The CSAPR was challenged in the courts.  The U.S. Court of Appeals for the District of Columbia Circuit issued an order in December 2011 staying the effective date of the rule pending judicial review.  In 2012, a panel of the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing CAIR until a replacement rule is finalized.  That decision has been appealed to the U.S. Supreme Court.  Nearly all of the states in which our power plants are located are covered by CAIR.

The Federal EPA issued the final maximum achievable control technology (MACT) standards for coal and oil-fired power plants (discussed in detail below) in 2012.

The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s requirement that certain facilities install best available retrofit technology (BART) to address regional haze in federal parks and other protected areas.  BART requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants.  CAVR will be implemented through individual state implementation plans (SIPs) or, if SIPs are not adequate or are not developed on schedule, through federal implementation plans (FIPs).  The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas.  The Arkansas SIP was disapproved and the state is developing a revised submittal.  In June 2012, the Federal EPA published revisions to the regional haze rules to allow states participating in the CSAPR trading programs to use those programs in place of source-specific BART for SO2 and NOx emissions based on its determination that CSAPR results in greater visibility improvements than source-specific BART in the CSAPR states.  This rule is being challenged in the U.S. Court of Appeals for the District of Columbia Circuit and its fate is uncertain given developments in the CSAPR litigation.

In 2009, the Federal EPA issued a final mandatory reporting rule for CO2 and other greenhouse gases covering a broad range of facilities emitting in excess of 25,000 tons of CO2 emissions per year.   The Federal EPA issued a final endangerment finding for greenhouse gas emissions from new motor vehicles in 2009.  The Federal EPA determined that greenhouse gas emissions from stationary sources will be subject to regulation under the CAA beginning January 2011 and finalized its proposed scheme to streamline and phase-in regulation of stationary source CO2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs through the issuance of final federal rules, SIP calls and FIPs.  The Federal EPA has proposed to include CO2 emissions in standards that apply to new electric utility units and will consider whether such standards are appropriate for other source categories in the future.

The Federal EPA has also issued new, more stringent national ambient air quality standards (NAAQS) for PM, SO2, NOx and lead, and is currently reviewing the NAAQS for ozone.  States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for our facilities as a result of those evaluations.  We cannot currently predict the nature, stringency or timing of those requirements.

Notable developments in significant CAA regulatory requirements affecting our operations are discussed in the following sections.

Cross-State Air Pollution Rule (CSAPR)

In 2011, the Federal EPA issued CSAPR.  Certain revisions to the rule were finalized in 2012.  CSAPR relies on newly-created SO2 and NOx allowances and individual state budgets to compel further emission reductions from electric utility generating units in 28 states.  Interstate trading of allowances is allowed on a restricted sub-regional basis.  Arkansas and Louisiana are subject only to the seasonal NOx program in the rule.  Texas is subject to the annual programs for SO2 and NOx in addition to the seasonal NOx program.  The annual SO2 allowance budgets in Indiana, Ohio and West Virginia were reduced significantly in the rule.  A supplemental rule includes Oklahoma in the seasonal NOx program.  The supplemental rule was finalized in December 2011 with an increased NOx emission budget for the 2012 compliance year.  The Federal EPA issued a final Error Corrections Rule and further CSAPR revisions in 2012 to make corrections to state budgets and unit allocations and to remove the restrictions on interstate trading in the first phase of CSAPR.
 
 
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Numerous affected entities, states and other parties filed petitions to review the CSAPR in the U.S. Court of Appeals for the District of Columbia Circuit.  Several of the petitioners filed motions to stay the implementation of the rule pending judicial review.  In 2011, the court granted the motions for stay.  In 2012, the panel issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing the Clean Air Interstate Rule until a replacement rule is finalized.  The majority determined that the CAA does not allow the Federal EPA to “overcontrol” emissions in an upwind state and that the Federal EPA exceeded its statutory authority by failing to allow states an opportunity to develop their own implementation plans before issuing a FIP.  The Federal EPA and other respondents filed petitions for rehearing but in January 2013, the U.S. Court of Appeals for the District of Columbia Circuit denied all petitions for rehearing.  The petition for further review filed by the Federal EPA and other parties in the U.S. Supreme Court was granted in June 2013.  Separate appeals of the supplemental rule, the Error Corrections Rule and the further revisions have been filed, but are being held in abeyance.

The time frames and stringency of the required emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and our electric utility customers.  We cannot predict the outcome of the pending litigation.

Mercury and Other Hazardous Air Pollutants Regulation

In 2012, the Federal EPA issued a rule addressing a broad range of HAPs from coal and oil-fired power plants.  The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrogen chloride (as a surrogate for acid gases) for units burning coal on a site-wide 30-day rolling average basis.  In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans.  The effective date of the final rule was April 16, 2012 and compliance is required within three years.  We are participating through various organizations in the petitions for administrative reconsideration and judicial review that have been filed.  In 2012, the Federal EPA published a notice announcing that it would accept comments on its reconsideration of certain issues related to the new source standards, including clarification of the requirements that apply during periods of start-up and shut down, measurement issues and the application of variability factors that may have an impact on the level of the standards.  The Federal EPA issued revisions to the new source standards consistent with the proposed rule, except the start-up and shut down provisions in March 2013.  The Federal EPA is still considering additional changes to the start-up and shut down provisions.

The final rule contains a slightly less stringent PM limit for existing sources than the original proposal and allows operators to exclude periods of start-up and shut down from the emissions averaging periods.  The compliance time frame remains a serious concern.  A one-year administrative extension may be available if the extension is necessary for the installation of controls or to avoid a serious reliability problem.  In addition, the Federal EPA issued an enforcement policy describing the circumstances under which an administrative consent order might be issued to provide a fifth year for the installation of controls or completion of reliability upgrades.  We are concerned about the availability of compliance extensions and the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines.  We are participating in petitions for review filed in the U.S. Court of Appeals for the District of Columbia Circuit by several organizations of which we are members.  Certain issues related to the standards for new coal-fired units have been severed from the main case and are being held in abeyance pending completion of the Federal EPA’s reconsideration proceeding.  The case is briefed and argued, and remains pending before the court.

Regional Haze

In 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze SIP submitted by the State of Oklahoma through the Department of Environmental Quality.  The Federal EPA proposed to approve all of the NOx control measures in the SIP and disapprove the SO2 control measures for six electric generating units, including two units owned by PSO.  The Federal EPA finalized a FIP that would require these units to install technology capable of reducing SO2 emissions to 0.06 pounds per million British thermal units within five years of the effective date of the FIP.  PSO filed a petition for review of the FIP in the Tenth Circuit Court of Appeals and engaged in settlement discussions with the Federal EPA, the State of Oklahoma and other parties.  In November 2012, we notified the court that the parties had reached agreement on a settlement that would provide for submission of a revised Regional Haze SIP requiring the retirement of one coal-fired unit of PSO’s Northeastern Station no later
 
 
11

 
than 2016, installation of emission controls on the second coal-fired Northeastern unit in 2016 and retirement of the second unit no later than 2026.  The Tenth Circuit Court of Appeals is holding the appeal in abeyance pending implementation of the settlement.  A revised regional haze SIP was adopted by the State of Oklahoma and the Federal EPA approved the revised SIP in February 2014.  Upon publication of the final approval and withdrawal of the FIP, the Tenth Circuit proceeding will be dismissed.

CO2 Regulation

In March 2012, the Federal EPA issued a proposal to regulate CO2 emissions from new fossil fuel-fired electricity generating units.  The proposed rule establishes a new source performance standard of 1,000 pounds of CO2 per megawatt hour of electricity generated, a rate that most natural gas combined cycle units can meet, but that is substantially below the emission rate of a new pulverized coal generator or an integrated gas combined cycle unit that uses coal for fuel.  As proposed, the rule does not apply to new gas-fired stationary combustion turbines used as peaking units, does not apply to existing, modified or reconstructed sources and does not apply to units whose CO2 emission rate increases as a result of the addition of pollution control equipment to control criteria pollutant emissions or HAPs.  The rule is not anticipated to have a significant immediate impact on the AEP System since it does not apply to existing units or units that have already commenced construction.  New source performance standards affect units that have not yet received permits.  The proposed standards were challenged in the U.S. Court of Appeals for the District of Columbia Circuit.  That case was dismissed because the court determined that no final agency action had yet been taken.

In June 2013, President Obama issued a memorandum to the Administrator of the Federal EPA directing the agency to develop and issue a new proposal regulating carbon emissions from new electric generating units in September 2013.  The new proposal was issued in September 2013 and requires new large natural gas units to meet 1,000 pounds of CO2 per MWh of electricity generated and small natural gas units to meet 1,100 pounds of CO2 per MWh.  New coal-fired units are required to meet the 1,100 pounds of CO2 per MWh limit, with the option to meet the tighter limits if they choose to average emissions over multiple years.  This proposal was published in the Federal Register in January 2014 and the March 2012 proposal has been withdrawn.

The Federal EPA was also directed to develop and issue a separate proposal regulating carbon emissions from existing, modified and reconstructed electric generating units before June 2014, to finalize those standards by June 2015 and to require states to submit revisions to their implementation plans including such standards no later than June 2016.  The President directed the Federal EPA, in developing this proposal, to directly engage states, leaders in the power sector, labor leaders and other stakeholders, to tailor the regulations to reduce costs, to develop market-based instruments and allow regulatory flexibilities and “assure that the standards are developed and implemented in a manner consistent with the continued provision of reliable and affordable electric power.”  We cannot currently predict the impact these programs may have on future resource plans or our existing generating fleet, but the costs may be substantial.

In June 2012, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision upholding, in all material respects, the Federal EPA’s endangerment finding, its regulatory program for CO2 emissions from new motor vehicles and its plan to phase in regulation of CO2 emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V operating permit programs.  A petition for rehearing was filed which the court denied in December 2012.  The U.S. Supreme Court granted several petitions for review and will determine whether the Federal EPA made a reasonable determination that adoption of the motor vehicle standards trigger PSD and Title V permitting obligations for stationary sources.  A decision is expected by June 2014.

The Federal EPA also finalized a rule in June 2012 that retains the current thresholds for permitting stationary sources under the PSD and Title V operating permit programs at 100,000 tons per year for new sources and 75,000 tons per year for modified sources.  The Federal EPA also confirmed that it will re-evaluate these thresholds during its five-year review in 2016.  Our generating units are large sources of CO2 emissions and we will continue to evaluate the permitting obligations in light of these thresholds.
 
 
12

 

Coal Combustion Residual Rule

In 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at coal-fired electric generating units.  The rule contains two alternative proposals.  One proposal would impose federal hazardous waste disposal and management standards on these materials and another would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management.  Both proposals would impose stringent requirements for the construction of new coal ash landfills and would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and initiate closure within five years of the issuance of a final rule.  In 2011, the Federal EPA issued a notice of data availability requesting comments on a number of technical reports and other data received during the comment period for the original proposal and requesting comments on potential modeling analyses to update its risk assessment.  In 2013, the Federal EPA also issued a notice of data availability requesting comments on a narrow set of items.

Various environmental organizations and industry groups filed a petition seeking to establish deadlines for a final rule.  The Federal EPA opposed the petition and sought additional time to coordinate the issuance of a final rule with the issuance of new effluent limitations under the Clean Water Act for utility facilities.  In October 2013, the U.S. District Court for the District of Columbia issued a final order partially ruling in favor of the Federal EPA for dismissal of two counts, ruling in favor of the environmental organizations on one count and directing the Federal EPA to provide the court with a proposed schedule for completion of the rulemaking.  In January 2014, the parties filed a motion with the court to establish December 2014 as the Federal EPA’s deadline for publication of the rule.  The court will establish a deadline for the final rule following a comment period for interested parties.

In February 2014, the Federal EPA completed an evaluation of the beneficial uses of coal fly ash in concrete and wallboard and concluded that the Federal EPA supports these beneficial uses.  Currently, approximately 40% of the coal ash and other residual products from our generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses.  Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes.  In addition, we currently use surface impoundments and landfills to manage these materials at our generating facilities and will incur significant costs to upgrade or close and replace these existing facilities under the proposed solid waste management alternative.  Regulation of these materials as hazardous wastes would significantly increase these costs.  As the rule is not final, we are unable to determine a range of potential costs that are reasonably possible of occurring but expect the costs to be significant.

Clean Water Act Regulations

In 2011, the Federal EPA issued a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against a plant’s cooling water intake screen (impingement) or entrained in the cooling water.  Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress.  The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement.  Compliance with this standard is required within eight years of the effective date of the final rule.  The proposed standard for entrainment for existing facilities requires a site-specific evaluation of the available measures for reducing entrainment.  The proposed entrainment standard for new units at existing facilities requires either intake flows commensurate with closed cycle cooling or achieving entrainment reductions equivalent to 90% or greater of the reductions that could be achieved with closed cycle cooling.  Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority.  We are evaluating the proposal and engaged in the collection of additional information regarding the feasibility of implementing this proposal at our facilities.  In June 2012, the Federal EPA issued additional Notices of Data Availability and requested public comments.  We submitted comments in July 2012.  Issuance of a final rule is expected in 2014.  We are preparing to begin activities to implement the rule following its issuance and an analysis of the final requirements.
 
 
13

 

In addition, the Federal EPA issued an information collection request and is developing revised effluent limitation guidelines for electricity generating facilities.  A proposed rule was signed in April 2013 with a final rule expected in 2014.  The Federal EPA proposed eight options of increasing stringency and cost for fly ash and bottom ash transport water, scrubber wastewater, leachate from coal combustion byproduct landfills and impoundments and other wastewaters associated with coal-fired generating units, with four labeled preferred options.  Certain of the Federal EPA's preferred options have already been implemented or are part of our long-term plans.  We continue to review the proposal in detail to evaluate whether our plants are currently meeting the proposed limitations, what technologies have been incorporated into our long-range plans and what additional costs might be incurred if the Federal EPA's most stringent options were adopted.  We submitted detailed comments to the Federal EPA in September 2013 and participated in comments filed by various organizations of which we are members.

Climate Change

National public policy makers and regulators in the 11 states we serve have diverse views on climate change.  We are currently focused on responding to these emerging views with prudent actions, such as improving energy efficiency, investing in developing cost-effective and less carbon-intensive technologies and evaluating our assets across a range of plausible scenarios and outcomes.  We are also active participants in a variety of public policy discussions at state and federal levels to assure that proposed new requirements are feasible and the economies of the states we serve are not placed at a competitive disadvantage.

While comprehensive economy-wide regulation of CO2 emissions might be achieved through future legislation, Congress has yet to enact such legislation.  The Federal EPA continues to take action to regulate CO2 emissions under the existing requirements of the CAA.

Several states have adopted programs that directly regulate CO2 emissions from power plants.  The majority of the states where we have generating facilities have passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements.  We are taking steps to comply with these requirements.  In order to meet these requirements and as a key part of our corporate sustainability effort, we pledged to increase our wind power.

We have taken measurable, voluntary actions to reduce and offset our CO2 emissions.  We estimate that our 2013 emissions were approximately 115 million metric tons.  This represents a reduction of 21% compared to our 2005 CO2 emissions of approximately 145 million metric tons.

Future federal and state legislation or regulations that mandate limits on the emission of CO2 could result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs.  Excessive costs to comply with future legislation or regulations might force our utility subsidiaries to close some coal-fired facilities and could lead to possible impairment of assets.  Public perception may ultimately have a significant impact on future legislation and regulation that could adversely affect our ability to recover our investments in coal-fired plants.

Climate change and its resultant impact on weather patterns could modify our customers’ power usage.  Our customers’ energy needs currently vary with weather conditions and the economy.  Increased or decreased energy usage could require the acquisition or construction of more generation and transmission assets or cause early retirement of such assets.  The timing and duration of extreme weather conditions may require more system backup and contribute to increased system stresses, including service interruptions and increased storm restoration costs.  Extreme weather conditions that create high energy demand could raise electricity prices, which could increase the cost of energy we provide to our customers and could provide opportunity for increased wholesale sales and higher margins.

To the extent climate change affects a region’s economic health, it could also affect our revenues.  Our financial performance is tied to the health of the regional economies we serve.  The price of energy, as a factor in a region's cost of living as well as an important input into the cost of goods, has an impact on the economic health of our communities.  The cost of additional regulatory requirements would normally be borne by consumers through higher prices for energy and purchased goods.


 
14

 


RESULTS OF OPERATIONS

SEGMENTS

Our primary business is the generation, transmission and distribution of electricity.  Within our Vertically Integrated Utilities segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight.  Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.

During the fourth quarter of 2013, we realigned our business segments as a result of corporate separation and plant transfers.  We retrospectively adjusted 2012 and 2011 segment information to reflect our new business segments.  See the “Corporate Separation” section of Executive Overview.

Our reportable segments and their related business activities are outlined below:

Vertically Integrated Utilities

·
Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.

Transmission and Distribution Utilities

·
Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC.
·
OPCo purchases energy and capacity to serve remaining generation service customers.

Generation & Marketing

·
Nonregulated generation in ERCOT and PJM.
·
Marketing, risk management and retail activities in ERCOT, PJM and MISO.

AEP Transmission Holdco

·
Development, construction and operation of transmission facilities through investments in our wholly-owned transmission only subsidiaries and transmission only joint ventures.  These investments have PUCT-approved or FERC-approved returns on equity.

AEP River Operations

·
Commercial barging operations that transports liquids, coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.

The table below presents Income Before Extraordinary Item by segment for the years ended December 31, 2013, 2012 and 2011.

 
 
 Years Ended December 31,
 
 
2013 
 
2012 
 
2011 
 
 
(in millions)
Vertically Integrated Utilities
$
 681 
 
$
 803 
 
$
 710 
Transmission and Distribution Utilities
 
 358 
 
 
 389 
 
 
 404 
Generation & Marketing
 
 228 
 
 
 100 
 
 
 439 
AEP Transmission Holdco
 
 80 
 
 
 43 
 
 
 30 
AEP River Operations
 
 12 
 
 
 15 
 
 
 45 
Corporate and Other (a)
 
 125 
 
 
 (88)
 
 
 (52)
Income Before Extraordinary Item
$
 1,484 
 
$
 1,262 
 
$
 1,576 

(a)
While not considered a reportable segment, Corporate and Other primarily includes management and professional services to AEP provided at cost to AEP subsidiaries and the purchasing of receivables from certain AEP utility subsidiaries.  This segment also includes parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
 
 
15

 

 
AEP CONSOLIDATED

2013 Compared to 2012

Income Before Extraordinary Item increased from $1,262 million in 2012 to $1,484 million in 2013 primarily due to:

·
Successful rate proceedings in our various jurisdictions.
·
2012 impairments of certain Ohio generation plants.
·
A decrease in Ohio depreciation expense due to impairments of certain Ohio generation plants.
·
A favorable U.K. Windfall Tax decision by the U.S. Supreme Court in 2013.

These increases were partially offset by:

·
Impairments during 2013 for the following:
 
·
Muskingum River Plant, Unit 5.
 
·
A write-off from a disallowance of a portion of Amos Plant, Unit 3 pursuant to a Virginia SCC order.
 
·
A decision from the KPSC disallowing scrubber costs on KPCo's Big Sandy Plant.
·
The loss of retail generation customers in Ohio to various CRES providers.
·
2012 reversal of a 2011 recorded obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of OPCo's modified stipulation.

2012 Compared to 2011

Income Before Extraordinary Item decreased from $1,576 million in 2011 to $1,262 million in 2012 primarily due to:

·
A decrease in carrying costs income due to the recognition in 2011 of a regulatory asset related to TCC capacity auction true-up amounts that were originally written off in 2005 and a related favorable 2011 resolution of contested tax items related to the TCC stranded cost settlement.
·
2012 impairments of certain Ohio generation plants.
·
The loss of retail generation customers in Ohio to various CRES providers.
·
A decrease in weather-related usage.
·
The elimination of POLR charges, effective June 2011, partially offset by the 2011 provision for refund of POLR charges.  The refund provision was recorded as a result of the October 2011 PUCO remand order.
·
Expenses associated with the early retirement of Parent debt in 2012.
·
Expenses related to the 2012 sustainable cost reductions.
·
The 2012 adjustment of a U.K. Windfall Tax provision as a result of a related Supreme Court case.

These decreases were partially offset by:

·
Successful rate proceedings in our various jurisdictions.
·
Lower spending in 2012 as a result of our cost containment efforts.
·
A 2011 recording and subsequent 2012 reversal of an obligation to contribute to Partnership with Ohio and Ohio Growth Fund as a result of the PUCO's February 2012 rejection of OPCo's modified stipulation.
·
The 2011 plant impairments for Sporn Plant, Unit 5 and for the FGD project at Muskingum River Plant, Unit 5.
·
The 2011 write-off related to SWEPCo's expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap as a result of the November 2011 Texas Court of Appeals decision.
·
A loss incurred in 2011 related to a settlement of litigation with BOA and Enron.

Our results of operations are discussed below by operating segment.


 
16

 


VERTICALLY INTEGRATED UTILITIES

 
 
 
Years Ended December 31,
Vertically Integrated Utilities
 
2013 
 
2012 
 
2011 
 
 
 
(in millions)
Revenues
 
$
 9,992 
 
$
 9,418 
 
$
 9,702 
Fuel and Purchased Electricity
 
 
 4,770 
 
 
 4,408 
 
 
 4,870 
Gross Margin
 
 
 5,222 
 
 
 5,010 
 
 
 4,832 
Other Operation and Maintenance
 
 
 2,276 
 
 
 2,219 
 
 
 2,237 
Asset Impairments and Other Related Charges
 
 
 72 
 
 
 13 
 
 
 49 
Depreciation and Amortization
 
 
 941 
 
 
 873 
 
 
 785 
Taxes Other Than Income Taxes
 
 
 372 
 
 
 344 
 
 
 339 
Operating Income
 
 
 1,561 
 
 
 1,561 
 
 
 1,422 
Interest and Investment Income
 
 
 7 
 
 
 5 
 
 
 13 
Carrying Costs Income
 
 
 14 
 
 
 28 
 
 
 17 
Allowance for Equity Funds Used During Construction
 
 
 35 
 
 
 72 
 
 
 82 
Interest Expense
 
 
 (540)
 
 
 (520)
 
 
 (514)
Income Before Income Tax Expense and Equity Earnings
 
 
 1,077 
 
 
 1,146 
 
 
 1,020 
Income Tax Expense
 
 
 398 
 
 
 345 
 
 
 312 
Equity Earnings of Unconsolidated Subsidiaries
 
 
 2 
 
 
 2 
 
 
 2 
Income Before Extraordinary Item
 
$
 681 
 
$
 803 
 
$
 710 

Summary of KWh Energy Sales for Vertically Integrated Utilities
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
 
(in millions of KWhs)
Retail:
 
 
 
 
 
 
 
 
 
Residential
 
 33,851 
 
 
 33,199 
 
 
 35,135 
 
Commercial
 
 25,037 
 
 
 25,278 
 
 
 25,651 
 
Industrial
 
 34,216 
 
 
 34,692 
 
 
 34,333 
 
Miscellaneous
 
 2,284 
 
 
 2,356 
 
 
 2,349 
Total Retail
 
 95,388 
 
 
 95,525 
 
 
 97,468 
 
 
 
 
 
 
 
 
 
Wholesale
 
 31,919 
 
 
 28,671 
 
 
 28,290 
 
 
 
 
 
 
 
 
 
Total KWhs
 
 127,307 
 
 
 124,196 
 
 
 125,758 
 
 
 
 
 
 
 
 
 
 


 
17

 


Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.  In general, degree day changes in our eastern region have a larger effect on net income than changes in our western region due to the relative size of the two regions and the number of customers within each region.

Summary of Heating and Cooling Degree Days for Vertically Integrated Utilities
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
2013 
 
2012 
 
2011 
 
 
(in degree days)
Eastern Region
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 2,949 
 
 
 2,216 
 
 
 2,566 
Normal - Heating (b)
 
 2,734 
 
 
 2,774 
 
 
 2,772 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 1,040 
 
 
 1,253 
 
 
 1,280 
Normal - Cooling (b)
 
 1,080 
 
 
 1,079 
 
 
 1,066 
 
 
 
 
 
 
 
 
 
 
Western Region
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 1,772 
 
 
 1,070 
 
 
 1,582 
Normal - Heating (b)
 
 1,501 
 
 
 1,537 
 
 
 1,534 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 2,163 
 
 
 2,635 
 
 
 2,830 
Normal - Cooling (b)
 
 2,202 
 
 
 2,186 
 
 
 2,165 
 
 
 
 
 
 
 
 
 
 
(a)
Eastern Region and Western Region heating degree days are calculated on a 55 degree temperature base.
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
(c)
Eastern Region and Western Region cooling degree days are calculated on a 65 degree temperature base.

 
18

 

2013 Compared to 2012
 
Reconciliation of Year Ended December 31, 2012 to Year Ended December 31, 2013
Income from Vertically Integrated Utilities Before Extraordinary Item
(in millions)
Year Ended December 31, 2012
 
 
 
 
$
 803 
 
 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
 
 
Retail Margins
 
 
 
 
 
 196 
Off-system Sales
 
 
 
 
 
 (26)
Transmission Revenues
 
 
 
 
 
 41 
Other Revenues
 
 
 
 
 
 1 
Total Change in Gross Margin
 
 
 
 
 
 212 
 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
 
 
Other Operation and Maintenance
 
 
 
 
 
 (57)
Asset Impairments and Other Related Charges
 
 
 
 
 
 (59)
Depreciation and Amortization
 
 
 
 
 
 (68)
Taxes Other Than Income Taxes
 
 
 
 
 
 (28)
Interest and Investment Income
 
 
 
 
 
 2 
Carrying Costs Income
 
 
 
 
 
 (14)
Allowance for Equity Funds Used During Construction
 
 
 
 
 
 (37)
Interest Expense
 
 
 
 
 
 (20)
Total Change in Expenses and Other
 
 
 
 
 
 (281)
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 
 
 
 (53)
 
 
 
 
 
 
 
 
Year Ended December 31, 2013
 
 
 
 
$
 681 

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:

·
Retail Margins increased $196 million primarily due to the following:
 
·
Successful rate proceedings in our service territories, which include:
   
·
A $153 million rate increase for SWEPCo.
   
·
A $112 million rate increase for I&M.
   
·
A $9 million rate increase for APCo.
     
For the rate increases described above, $42 million relates to riders/trackers which have corresponding increases in other expense items below.
 
·
A $29 million increase in weather-related usage in our eastern and western regions primarily due to increases of 33% and 66%, respectively, in heating degree days partially offset by decreases in our eastern and western regions of 17% and 18%, respectively, in cooling degree days.
 
These increases were partially offset by:
 
·
A $15 million decrease in SWEPCo's municipal and cooperative revenues primarily due to lower realizations from changes in sales volume mix.
 
·
A $23 million decrease due to lower weather normalized retail sales.
 
·
A $12 million increase in other variable electric generation expenses.
 
·
A $9 million deferral of APCo's additional wind purchase costs in 2012 as a result of the June 2012 Virginia SCC fuel factor order.
 
·
A $9 million decrease due to adjustments for previously disallowed environmental costs by the November 2011 Virginia SCC order subsequently determined in 2012 to be appropriate for recovery by the Supreme Court of Virginia.
·
Margins from Off-system Sales decreased $26 million primarily due to lower PJM capacity revenue, reduced trading and marketing margins, partially offset by higher prices and volumes.
·
Transmission Revenues increased $41 million primarily due to increased investment in the PJM and SPP regions.  These increased revenues are offset-in-part in Other Operation and Maintenance expenses below.

 
19

 
Expenses and Other and Income Tax Expense changed between years as follows:

·
Other Operation and Maintenance expenses increased $57 million primarily due to the following:
 
·
A $33 million increase in recoverable PJM and other expenses currently recovered dollar-for-dollar in rate recovery riders/trackers.
 
·
A $30 million write-off in 2013 of previously deferred 2012 Virginia storm costs resulting from the 2013 enactment of a Virginia law.
 
·
A $22 million increase in storm-related expenses primarily in APCo's service territory.
 
·
A $21 million increase in plant outage expenses.
 
These increases were partially offset by:
 
·
A $26 million decrease due to expenses related to the 2012 sustainable cost reductions.
 
·
A $25 million decrease due to an agreement reached to settle an insurance claim in 2013.
·
Asset Impairments and Other Related Charges increased $59 million primarily due to the following:
 
·
A $39 million increase due to APCo's 2013 write-off from a regulatory disallowance of a portion of Amos Plant, Unit 3 pursuant to a Virginia SCC order approving the transfer of Amos Plant, Unit 3.
 
·
A $33 million increase due to KPCo's 2013 write-off of scrubber costs on the Big Sandy Plant and other generation costs in accordance with a KPSC's October 2013 order.
 
These increases were partially offset by:
 
·
A 2012 write-off of an additional $13 million related to SWEPCo's expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap.
·
Depreciation and Amortization expenses increased $68 million primarily due to the following:
 
·
A $40 million increase due to the Turk Plant being placed in service in December 2012.
 
·
A $26 million increase due to higher depreciable base and higher depreciation rates reflecting a change in Tanners Creek Plant's estimated life approved by the MPSC effective April 2012 and by the IURC effective March 2013.  The majority of the increase in depreciation for Tanners Creek Plant's life is offset within Gross Margin.
 
·
Overall higher depreciable property balances.
 
These increases were partially offset by:
 
·
A $13 million decrease in amortization as a result of the cessation of the Virginia Environmental and Reliability surcharge and the Virginia Environmental Rate Adjustment Clause in January 2013 and March 2013, respectively.
·
Taxes Other Than Income Taxes increased $28 million primarily due to increased property taxes as a result of increased capital investments.
·
Carrying Costs Income decreased $14 million primarily due to an increased recovery of Virginia environmental costs in new base rates as approved by the Virginia SCC in late January 2012 and decreased carrying charges related to the Dresden Plant.
·
Allowance for Equity Funds Used During Construction decreased $37 million primarily due to completed construction of the Turk Plant in December 2012.
·
Interest Expense increased $20 million primarily due to a decrease in the debt component of AFUDC due to completed construction of the Turk Plant in December 2012 partially offset by lower average outstanding long-term debt balances and an increase in the debt component of AFUDC related to projects at the Cook Plant.
·
Income Tax Expense increased $53 million primarily due to the recording of federal and state income tax adjustments and other book/tax differences which are accounted for on a flow-through basis, offset-in-part by a decrease in pretax book income.

 
20

 

2012 Compared to 2011
 
Reconciliation of Year Ended December 31, 2011 to Year Ended December 31, 2012
Income from Vertically Integrated Utilities Before Extraordinary Item
(in millions)

Year Ended December 31, 2011
 
 
 
 
$
 710 
 
 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
 
 
Retail Margins
 
 
 
 
 
 181 
Off-system Sales
 
 
 
 
 
 (13)
Transmission Revenues
 
 
 
 
 
 19 
Other Revenues
 
 
 
 
 
 (9)
Total Change in Gross Margin
 
 
 
 
 
 178 
 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
 
 
Other Operation and Maintenance
 
 
 
 
 
 18 
Asset Impairments and Other Related Charges
 
 
 
 
 
 36 
Depreciation and Amortization
 
 
 
 
 
 (88)
Taxes Other Than Income Taxes
 
 
 
 
 
 (5)
Interest and Investment Income
 
 
 
 
 
 (8)
Carrying Costs Income
 
 
 
 
 
 11 
Allowance for Equity Funds Used During Construction
 
 
 
 
 
 (10)
Interest Expense
 
 
 
 
 
 (6)
Total Change in Expenses and Other
 
 
 
 
 
 (52)
 
 
 
 
 
 
 
 
Income Tax Expense
 
 
 
 
 
 (33)
 
 
 
 
 
 
 
 
Year Ended December 31, 2012
 
 
 
 
$
 803 

The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased electricity were as follows:

·
Retail Margins increased $181 million primarily due to the following:
 
·
A $130 million increase due to lower capacity settlement expenses under the Interconnection Agreement, net of recovery in West Virginia and environmental deferrals in Virginia.  This increase was primarily a result of a mild winter in 2012 and its impact on APCo's winter peak, APCo's completion of the Dresden Plant in January 2012 and the removal of Sport Plant, Unit 5 from the Interconnection Agreement in September 2011.
 
·
Successful rate proceedings in our service territories which include:
   
·
An $87 million rate increase for APCo.
   
·
A $17 million rate increase for I&M.
   
·
A $13 million rate increase for PSO.
   
·
An $11 million rate increase for WPCo.
     
For the rate increases described above, $99 million relates to riders/trackers which have corresponding increases in other expense items below.
 
·
A $24 million write-off in 2011 related to APCo's disallowance of certain Virginia environmental costs incurred in 2009 and 2010 as a result of a November 2011 Virginia SCC order.
 
·
A $9 million deferral of APCo's additional wind purchase costs in 2012 as a result of a June 2012 Virginia SCC fuel factor order.
 
·
A $9 million increase due to adjustments for previously disallowed environmental costs by the November 2011 Virginia SCC order subsequently determined in 2012 to be appropriate for recovery by the Supreme Court of Virginia.
 
These increases were partially offset by:
 
·
A $71 million decrease in weather-related usage in our eastern and western regions primarily due to decreases of 14% and 32%, respectively, in heating degree days and a 7% decrease in cooling degree days in our western region.
 
 
21

 
·
Margins from Off-system Sales decreased $13 million primarily due to lower PJM capacity revenue, reduced trading and marketing margins and lower power prices.
·
Transmission Revenues increased $19 million primarily due to increased investment in the PJM region. These increased revenues are offset-in-part in Other Operation and Maintenance expenses below.
·
Other Revenues decreased $9 million primarily due to a decrease in miscellaneous sales partially offset by a 2011 unfavorable provision for refund of outage insurance proceeds.

Expenses and Other and Income Tax Expense changed between years as follows:

·
Other Operation and Maintenance expenses decreased $18 million primarily due to the following:
 
·
A $46 million decrease in plant outage and other plant operating and maintenance expenses.
 
·
A $41 million decrease due to the 2011 write-off of a portion of the West Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC.
 
·
A $13 million decrease due to APCo's deferral of transmission costs for the Virginia Transmission Rate Adjustment Clause as allowed by the Virginia SCC recovered dollar-for-dollar within Gross Margin.
 
These decreases were partially offset by:
 
·
A $33 million increase due to the 2011 deferral of 2009 storm costs and the 2010 cost reduction initiatives as allowed by the WVPSC.
 
·
A $27 million increase due to the favorable 2011 asset retirement obligation adjustment for APCo related to the early closure and previous write-off of the Mountaineer Carbon Capture and Storage Product Validation Facility.
 
·
A $26 million increase due to expenses related to the 2012 sustainable cost reductions.
·
Asset Impairments and Other Related Charges decreased $36 million due to the 2011 write-off of $49 million related to SWEPCo's expected Texas jurisdictional portion of the Turk Plant in excess of the Texas capital cost cap as a result of a November 2011 Texas Court of Appeals decision.  This was partially offset by the 2012 write-off of an additional $13 million related to SWEPCo's Texas capital cost cap.
·
Depreciation and Amortization expenses increased $88 million primarily due to the following:
 
·
A $48 million combined increase in depreciation for APCo and I&M primarily due to increases in depreciation rates effective February 2012 (Virginia) and April 2012 (Michigan), respectively.  The majority of this increase in depreciation is offset within Gross Margin.
 
·
An $18 million increase in amortization primarily as a result of the Virginia Environmental Rate Adjustment Clause and the Virginia E&R surcharge, both effective February 2012.  This increase in amortization is offset within Gross Margin.
 
·
Overall higher depreciable property balances.
·
Carrying Costs Income increased $11 million due to adjustments for disallowed environmental costs as approved in a November 2011 Virginia SCC order and 2012 adjustments for certain costs subsequently determined by the Supreme Court of Virginia to be appropriate for recovery.
·
Allowance for Equity Funds Used During Construction decreased $10 million primarily due to the completion of APCo's Dresden Plant in January 2012 and I&M's nuclear fuel preparation for usage, partially offset by increases related to SWEPCo's construction of the Turk Plant.
·
Income Tax Expense increased $33 million primarily due to an increase in pretax book income offset-in-part by the recording of federal and state income tax adjustments.


 
22

 


TRANSMISSION AND DISTRIBUTION UTILITIES

 
 
 
Years Ended December 31,
 
Transmission and Distribution Utilities
 
2013 
 
2012 
 
2011 
 
 
 
 
(in millions)
 
Revenues
 
$
 4,478 
 
$
 4,819 
 
$
 5,156 
 
Purchased Electricity
 
 
 1,627 
 
 
 2,072 
 
 
 2,711 
 
Gross Margin
 
 
 2,851 
 
 
 2,747 
 
 
 2,445 
 
Other Operation and Maintenance
 
 
 1,003 
 
 
 911 
 
 
 954 
 
Depreciation and Amortization
 
 
 591 
 
 
 561 
 
 
 549 
 
Taxes Other Than Income Taxes
 
 
 435 
 
 
 428 
 
 
 417 
 
Operating Income
 
 
 822 
 
 
 847 
 
 
 525 
 
Interest and Investment Income
 
 
 2 
 
 
 4 
 
 
 7 
 
Carrying Costs Income
 
 
 16 
 
 
 24 
 
 
 375 
 
Allowance for Equity Funds Used During Construction
 
 
 8 
 
 
 6 
 
 
 9 
 
Interest Expense
 
 
 (292)
 
 
 (291)
 
 
 (293)
 
Income Before Income Tax Expense
 
 
 556 
 
 
 590 
 
 
 623 
 
Income Tax Expense
 
 
 198 
 
 
 201 
 
 
 219 
 
Income Before Extraordinary Item
 
$
 358 
 
$
 389 
 
$
 404 
 

Summary of KWh Energy Sales for Transmission and Distribution Utilities
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
2013 
 
2012 
 
2011 
 
 
(in millions of KWhs)
Retail:
 
 
 
 
 
 
 
 
 
Residential
 
 25,531 
 
 
 25,581 
 
 
 26,520 
 
Commercial
 
 24,631 
 
 
 24,746 
 
 
 25,116 
 
Industrial
 
 22,668 
 
 
 24,902 
 
 
 25,334 
 
Miscellaneous
 
 710 
 
 
 716 
 
 
 751 
Total Retail (a)
 
 73,540 
 
 
 75,945 
 
 
 77,721 
 
 
 
 
 
 
 
 
 
Wholesale
 
 8 
 
 
 8 
 
 
 8 
 
 
 
 
 
 
 
 
 
Total KWhs
 
 73,548 
 
 
 75,953 
 
 
 77,729 
 
 
 
 
 
 
 
 
 
 
(a)  Represents energy delivered to distribution customers.


 
23

 


Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income.  In general, degree day changes in our eastern region have a larger effect on net income than changes in our western region due to the relative size of the two regions and the number of customers within each region.

Summary of Heating and Cooling Degree Days for Transmission and Distribution Utilities
 
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
2013 
 
2012 
 
2011 
 
 
(in degree days)
Eastern Region
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 3,383 
 
 
 2,610 
 
 
 3,107 
Normal - Heating (b)
 
 3,229 
 
 
 3,276 
 
 
 3,266 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (c)
 
 1,029 
 
 
 1,248 
 
 
 1,112 
Normal - Cooling (b)
 
 954 
 
 
 948 
 
 
 936 
 
 
 
 
 
 
 
 
 
 
Western Region
 
 
 
 
 
 
 
 
Actual - Heating (a)
 
 368 
 
 
 177 
 
 
 394 
Normal - Heating (b)
 
 337 
 
 
 352 
 
 
 351 
 
 
 
 
 
 
 
 
 
 
Actual - Cooling (d)
 
 2,737 
 
 
 3,100 
 
 
 3,242 
Normal - Cooling (b)
 
 2,608 
 
 
 2,584 
 
 
 2,557 
 
 
 
 
 
 
 
 
 
 
(a)
Heating degree days are calculated on a 55 degree temperature base.
(b)
Normal Heating/Cooling represents the thirty-year average of degree days.
(c)
Eastern Region cooling degree days are calculated on a 65 degree temperature base.
(d)
Western Region cooling degree days are calculated on a 70 degree temperature base.

 
24

 

2013 Compared to 2012
 
Reconciliation of Year Ended December 31, 2012 to Year Ended December 31, 2013
Income from Transmission and Distribution Utilities Before Extraordinary Item
(in millions)

Year Ended December 31, 2012
 
 
 
 
$
 389 
 
 
 
 
 
 
 
 
Changes in Gross Margin:
 
 
 
 
 
 
Retail Margins
 
 
 
 
 
 55 
Off-System Sales
 
 
 
 
 
 1 
Transmission Revenues
 
 
 
 
 
 46 
Other Revenues
 
 
 
 
 
 2 
Total Change in Gross Margin
 
 
 
 
 
 104 
 
 
 
 
 
 
 
Changes in Expenses and Other:
 
 
 
 
 
 
Other Operation and Maintenance
 
 
 
 
 
 (92)
Depreciation and Amortization
 
 
 
 
 
 (30)
Taxes Other Than Income Taxes
 
 
 
 
 
 (7)
Interest and Investment Income
 
 
 
 
 
 (2)
Carrying Costs Income
 
 
 
 
 
 (8)
Allowance for Equity Funds Used During Construction
 
 
 
 
 
 2 
Interest Expense