EX-13 14 ye14aepar.htm ANNUAL REPORT AEP EX 13


2014 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















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



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.
AEP System
 
American Electric Power System, an electric system, owned and operated by AEP subsidiaries.
AEP Transmission Holdco
 
AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.
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 in the Generation & Marketing segment.
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.
ASU
 
Accounting Standards Update.
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.
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.
DCC Fuel
 
DCC Fuel IV LLC, DCC Fuel V LLC, DCC Fuel VI LLC and DCC Fuel VII, 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.
EIS
 
Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated variable interest entity of AEP.
ENEC
 
Expanded Net Energy Charge.

i


Term
 
Meaning
 
 
 
Energy Supply
 
AEP Energy Supply LLC, a nonregulated holding company for AEP’s competitive generation, wholesale and retail businesses, and a wholly-owned subsidiary of AEP.
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 Berkshire Hathaway Energy Company 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.
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.

ii


Term
 
Meaning
 
 
 
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.
PIRR
 
Phase-In Recovery Rider.
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.
RPM
 
Reliability Pricing Model.
RSR
 
Retail Stability Rider.
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, as amended, 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.
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 Legislation.
Transource Energy
 
Transource Energy, LLC, a consolidated variable interest entity formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates.
Transource Missouri
 
A 100% wholly-owned subsidiary of Transource Energy.
Turk Plant
 
John W. Turk, Jr. Plant, a 600 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.

iii


Term
 
Meaning
 
 
 
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:
Ÿ
The economic climate, growth or contraction within and changes in market demand and demographic patterns in our service territory.
Ÿ
Inflationary or deflationary interest rate trends.
Ÿ
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.
Ÿ
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.
Ÿ
Electric load, customer growth and the impact of competition, including competition for retail customers.
Ÿ
Weather conditions, including storms and drought conditions, and our ability to recover significant storm restoration costs.
Ÿ
Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters.
Ÿ
Availability of necessary generation capacity and the performance of our generation plants.
Ÿ
Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
Ÿ
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.
Ÿ
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.
Ÿ
Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel.
Ÿ
A reduction in the federal statutory tax rate could result in an accelerated return of deferred federal income taxes to customers.
Ÿ
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.
Ÿ
Resolution of litigation.
Ÿ
Our ability to constrain operation and maintenance costs.
Ÿ
Our ability to develop and execute a strategy based on a view regarding prices of electricity and other energy-related commodities.
Ÿ
Prices and demand for power that we generate and sell at wholesale.
Ÿ
Changes in technology, particularly with respect to new, developing, alternative or distributed sources of generation.
Ÿ
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.
Ÿ
Volatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the price of natural gas and capacity auction returns.
Ÿ
Changes in utility regulation and the allocation of costs within regional transmission organizations, including ERCOT, PJM and SPP.

v


Ÿ
The transition to market for generation in Ohio, including the implementation of ESPs and our ability to recover investments in our Ohio generation assets.
Ÿ
Our ability to successfully and profitably manage our separate competitive generation assets.
Ÿ
Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
Ÿ
Actions of rating agencies, including changes in the ratings of our debt.
Ÿ
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 of such volatility on future funding requirements.
Ÿ
Accounting pronouncements periodically issued by accounting standard-setting bodies.
Ÿ
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 Ended
 
High
 
Low
 
Quarter-End
Closing Price
 
Dividend
December 31, 2014
 
$
63.22

 
$
51.97

 
$
60.72

 
$
0.53

September 30, 2014
 
55.91

 
49.06

 
52.21

 
0.50

June 30, 2014
 
55.94

 
49.99

 
55.77

 
0.50

March 31, 2014
 
50.95

 
45.80

 
50.66

 
0.50

 
 
 
 
 
 
 
 
 
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


AEP common stock is traded principally on the New York Stock Exchange.  As of December 31, 2014, AEP had approximately 74,000 registered shareholders.


vii



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
 
 
 
 
 
 
2014
 
2013
 
2012
 
2011
 
2010
 
 
(dollars in millions, except per share amounts)
STATEMENTS OF INCOME DATA
 
 
 
 
 
 
 
 
 
 
Total Revenues
 
$
17,020

 
$
15,357

 
$
14,945

 
$
15,116

 
$
14,427

 
 


 
 
 
 
 
 
 
 
Operating Income
 
$
3,232

 
$
2,855

 
$
2,656

 
$
2,782

 
$
2,663

 
 


 
 
 
 
 
 
 
 
Income Before Extraordinary Items
 
$
1,638

 
$
1,484

 
$
1,262

 
$
1,576

 
$
1,218

Extraordinary Items, Net of Tax
 

 

 

 
373

 

Net Income
 
1,638

 
1,484

 
1,262

 
1,949

 
1,218

 
 
 
 
 
 
 
 
 
 
 
Net Income Attributable to Noncontrolling Interests
 
4

 
4

 
3

 
3

 
4

 
 
 
 
 
 
 
 
 
 
 
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS
 
1,634

 
1,480

 
1,259

 
1,946

 
1,214

 
 
 
 
 
 
 
 
 
 
 
Preferred Stock Dividend Requirements of Subsidiaries Including Capital Stock Expense
 

 

 

 
5

 
3

 
 
 
 
 
 
 
 
 
 
 
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
 
$
1,634

 
$
1,480

 
$
1,259

 
$
1,941

 
$
1,211

 
 
 
 
 
 
 
 
 
 
 
BALANCE SHEETS DATA
 
 
 
 
 
 
 
 
 
 
Total Property, Plant and Equipment
 
$
64,305

 
$
60,285

 
$
57,454

 
$
55,670

 
$
53,740

Accumulated Depreciation and Amortization
 
20,188

 
19,288

 
18,691

 
18,699

 
18,066

Total Property, Plant and Equipment – Net
 
$
44,117

 
$
40,997

 
$
38,763

 
$
36,971

 
$
35,674

 
 
 
 
 
 
 
 
 
 
 
Total Assets
 
$
59,633

 
$
56,414

 
$
54,367

 
$
52,223

 
$
50,455

 
 


 
 
 
 
 
 
 
 
Total AEP Common Shareholders’ Equity
 
$
16,820

 
$
16,085

 
$
15,237

 
$
14,664

 
$
13,622

 
 


 
 
 
 
 
 
 
 
Noncontrolling Interests
 
$
4

 
$
1

 
$

 
$
1

 
$

 
 


 
 
 
 
 
 
 
 
Cumulative Preferred Stock Not Subject to Mandatory Redemption
 
$

 
$

 
$

 
$

 
$
60

 
 


 
 
 
 
 
 
 
 
Long-term Debt (a)
 
$
18,684

 
$
18,377

 
$
17,757

 
$
16,516

 
$
16,811

 
 


 
 
 
 
 
 
 
 
Obligations Under Capital Leases (a)
 
$
552

 
$
538

 
$
449

 
$
458

 
$
474

 
 


 
 
 
 
 
 
 
 
AEP COMMON STOCK DATA
 


 
 
 
 
 
 
 
 
Basic Earnings per Share Attributable to AEP Common Shareholders:
 


 
 
 
 
 
 
 
 
 
 


 
 
 
 
 
 
 
 
Income Before Extraordinary Items
 
$
3.34

 
$
3.04

 
$
2.60

 
$
3.25

 
$
2.53

Extraordinary Items, Net of Tax
 

 

 

 
0.77

 

 
 


 
 
 
 
 
 
 
 
Total Basic Earnings per Share Attributable to AEP Common Shareholders
 
$
3.34

 
$
3.04

 
$
2.60

 
$
4.02

 
$
2.53

 
 


 
 
 
 
 
 
 
 
Weighted Average Number of Basic Shares Outstanding (in millions)
 
489

 
487

 
485

 
482

 
479

 
 

 
 
 
 
 
 
 
 
Market Price Range:
 

 
 
 
 
 
 
 
 
High
 
$
63.22

 
$
51.60

 
$
45.41

 
$
41.71

 
$
37.94

Low
 
$
45.80

 
$
41.83

 
$
36.97

 
$
33.09

 
$
28.17

 
 


 
 
 
 
 
 
 
 
Year-end Market Price
 
$
60.72

 
$
46.74

 
$
42.68

 
$
41.31

 
$
35.98

 
 


 
 
 
 
 
 
 
 
Cash Dividends Declared per AEP Common Share
 
$
2.03

 
$
1.95

 
$
1.88

 
$
1.85

 
$
1.71

 
 


 
 
 
 
 
 
 
 
Dividend Payout Ratio
 
60.78
%
 
64.14
%
 
72.31
%
 
46.02
%
 
67.59
%
 
 


 
 
 
 
 
 
 
 
Book Value per AEP Common Share
 
$
34.37

 
$
32.98

 
$
31.35

 
$
30.36

 
$
28.32


(a)
Includes portion due within one year.

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.
Approximately 40,000 miles of transmission lines, including 2,110 miles of 765 kV 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 (approximately 4,990 railcars, approximately 2,800 barges, 47 towboats, 20 harbor boats and a coal handling terminal with approximately 18 million tons of annual capacity).  Our commercial barging operations annually transport approximately 48 million tons of coal and dry bulk commodities.  Approximately 35% of the barging is for transportation of agricultural products, 34% for coal, 17% for steel and 14% for other commodities.

Customer Demand

In comparison to 2013, our weather-normalized retail sales increased 1% for the year ended December 31, 2014. Our 2014 industrial sales increased 0.4% compared to 2013, despite the closure of Ormet, a large aluminum company in October 2013. Excluding Ormet, our industrial sales volumes increased by 3.9%. Our 2014 residential and commercial sales increased 1.1% and 1.7%, respectively, compared to 2013.
In 2015, we anticipate weather-normalized retail sales will increase by 0.6%. The industrial class is expected to grow by 2% in 2015, 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 increase by 0.2%, primarily related to projected customer growth. Commercial class energy sales are projected to decrease by 0.4%.

Corporate Separation

Background

On December 31, 2013, as approved by the FERC and the PUCO, 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 began purchasing 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 and one-half of its interest (780 MW) in the Mitchell Plant to KPCo.  


2


Other Impacts of Corporate Separation

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:

A PCA among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources.
A 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.
A Power Supply Agreement between AGR and OPCo for AGR to supply capacity for OPCo’s switched (at $188.88/MW day) 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 was not acquired through auctions in 2014.
 
For a further discussion of corporate separation, see the “Corporate Separation” section of Note 1.

Merchant Fleet Alternatives

AEP is evaluating strategic alternatives for its merchant generation fleet, which primarily includes AGR’s generation fleet and AEG's Lawrenceburg unit which operates in PJM as well as a 54.7% interest in the Oklaunion Plant which operates in ERCOT.  Potential alternatives may include, but are not limited to, continued ownership of the merchant generation fleet, executing a purchased power agreement with a regulated affiliate for certain merchant generation units in Ohio, a spin-off of the merchant generation fleet or a sale of the merchant generation fleet.  Management has not made a decision regarding the potential alternatives, nor has management set a specific time frame for a decision.  Certain of these alternatives could result in a loss which could reduce future net income and cash flow and impact financial condition.

Merchant Portion of 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.

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 (approximately 20%). Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN. 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 is currently not subject to cost-based rate recovery and is being sold into the wholesale market. Approximately 80% of the Turk plant is recovered under cost-based rate recovery in Texas, Louisiana, and through SWEPCo’s wholesale customers.

If SWEPCo cannot ultimately recover its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financial condition.


3


Ohio Electric Security Plan Filings

2009 - 2011 ESP

In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover OPCo’s deferred fuel costs in rates beginning September 2012. Oral arguments at the Supreme Court of Ohio were held in February 2015. OPCo presented arguments to reinstate a weighted average cost of capital carrying charge and to defend against an intervenor argument that the carrying charges should be reduced due to an accumulated deferred income tax credit. 
 
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 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 OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34/MW day through May 2014 and is $150/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 RSR, effective September 2012. The RSR was collected from customers at $3.50/MWh through May 2014 and is currently 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, 2014, OPCo’s incurred deferred capacity costs balance was $422 million, including debt carrying costs.

In November 2013, the PUCO issued an order approving OPCo’s competitive bid process with modifications. As ordered, in 2014, OPCo conducted multiple energy-only auctions for a total of 100% of the SSO load with delivery beginning April 2014 through May 2015. For delivery starting in June 2015, OPCo will conduct energy and capacity auctions for its entire SSO load. 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 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. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88 capacity charge, the independent auditor recommends a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and intends to oppose the findings in the audit report.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition.


4


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. The proposal included 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 capacity and energy auction-based generation through OPCo. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based purchase power agreement. In May 2014, intervenors and the PUCO staff filed testimony that provided various recommendations including the rejection and/or modification of various riders, including the Distribution Investment Rider and the proposed PPA. Hearings at the PUCO in the ESP case were held in June 2014.

In July 2014, OPCo submitted a separate application to continue the RSR established in the June 2012 - May 2015 ESP to collect the unrecovered portion of the deferred capacity costs at the rate of $4.00/MWh, until the balance of the capacity deferrals has been collected.

In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA for inclusion in the PPA rider, discussed above. The new PPA would include an additional 2,671 MW to be purchased from AGR over the life of the respective generating units.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. See “Ohio Electric Security Plan Filings” section of Note 4.

2012 Texas Base Rate Case

Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant’s Texas jurisdictional capital cost cap.  As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances.  The resulting annual base rate increase is approximately $52 million.  In May 2014, intervenors filed appeals of the order with the Texas District Court.  In June 2014, SWEPCo intervened in those appeals and filed initial responses.  If certain parts of the PUCT order are overturned it could reduce future net income and cash flows and impact financial condition.  See the “2012 Texas Base Rate Case” section 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 December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million, primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. See the “2012 Louisiana Formula Rate Filing” 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 included 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 transmission-related costs that are expected to increase over the next several years.

5


In June 2014, a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors was filed with the OCC. The parties to the stipulation recommended no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider would provide $24 million of revenues over 14 months beginning in November 2014 and increase to $27 million in 2016. New depreciation rates are recommended for advanced metering investments and existing meters, also to be effective November 2014. Additionally, the stipulation recommends recovery of regulatory assets for 2013 storms and regulatory case expenses. In July 2014, the Attorney General joined in the stipulation agreement. In October 2014, the Administrative Law Judge (ALJ) recommended approval of the stipulation agreement and interim rates were implemented in November 2014, subject to refund. In November 2014, intervenors filed exceptions to the ALJ's report. An order is anticipated in the first quarter of 2015. If the OCC were to disallow any portion of this settlement agreement, it could reduce future net income and cash flows and impact financial condition. See the “2014 Oklahoma Base Rate Case” section of Note 4.

2014 Virginia Biennial Base Rate Case

In March 2014, APCo filed a biennial generation and distribution base rate case with the Virginia SCC. In accordance with a Virginia statute, APCo did not request an increase in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 was within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to the change in the expected service life of certain plants. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to IGCC and other deferred costs. APCo also requested approval to amortize $38 million related to an accumulated deferred Virginia state income tax (ADVSIT) liability over 20 years, beginning February 2015.

In November 2014, the Virginia SCC issued an order concluding that APCo's adjusted earned rate of return on common equity for 2012 and 2013, reflecting their ordered adjustments, was above the allowed threshold. The order included (a) a $6 million refund to customers for the years 2012 through 2013, (b) the write-off of $10 million of IGCC pre-construction costs, (c) approval to amortize a $38 million ADVSIT liability over 20 years, beginning February 2015 and (d) no change to generation depreciation rates with rates to be reviewed again in the next biennial rate case. The order also approved a new return on common equity of 9.7% effective for 2014 and 2015. The Virginia SCC did not rule on a Virginia SCC staff recommendation to write-down certain costs, for ratemaking purposes, for the biennial period based on APCo’s earnings within the statutory equity range. In January 2015, the Virginia SCC initiated a separate proceeding to address the proper treatment of APCo’s authorized regulatory assets. If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2014 Virginia Biennial Base Rate Case” section of Note 4.

Potential New Virginia Legislation Affecting Biennial Reviews

In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were approved by the Virginia General Assembly and have been sent to the Governor. If these amendments are enacted, APCo’s existing generation and distribution base rates would freeze until after the Virginia SCC rules on APCo’s next biennial review, which APCo would file in March 2020 for the 2018 and 2019 test years. These amendments would also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. Management continues to monitor this potential new legislation in Virginia.

2014 West Virginia Base Rate Case

In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $181 million, based upon a 10.62% return on common equity, to be effective in the second quarter of 2015.  The filing included a request to increase generation depreciation rates primarily due to the increase in plant investment and changes in the expected service lives of various generating units.  The filing also requested recovery of $89 million over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs.  In addition to the base rate request, the filing also included a request to implement a rider of approximately $45 million annually to recover vegetation management costs, including

6


a return on capital investment.  In December 2014 and January 2015, intervenors filed testimony which proposed total annual revenue increases ranging from $35 million to $59 million based upon returns on common equity ranging from 9% to 10% and regulatory asset disallowances ranging from $7 million to $9 million.  Additionally, other intervenors proposed that the revenue requirement be based on a return on common equity of 8.7% and that $89 million of regulatory assets be disallowed.  Intervenors also recommended a disallowance of approximately $44 million related to the December 2013 transfer of OPCo's two-thirds interest in the Amos Plant, Unit 3 to APCo.  Hearings at the WVPSC were held in January 2015.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See the “2014 West Virginia Base Rate Case” section of Note 4.

Plant Transfer

APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a cost-of-service basis, to their respective customers. West Virginia generally allows for timely recovery of fuel costs through an expanded net energy cost which trues-up to actual expenses. In March 2014, APCo and WPCo filed a request with the WVPSC for approval to transfer at net book value to WPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by AGR. In April 2014, APCo and WPCo filed testimony that supported their request and proposed a base rate surcharge of $113 million, to be offset by an equal reduction in the ENEC revenues, to be effective upon the transfer of the Mitchell Plant to WPCo. In June 2014, the FERC issued an order approving a request by AGR and WPCo to transfer AGR’s one-half interest in the Mitchell Plant to WPCo.

In October 2014, a stipulation agreement between APCo, WPCo, the WVPSC staff and intervenors in the case was filed with the WVPSC. The stipulation agreement recommended approval for WPCo to acquire, at net book value, the one-half interest in the Mitchell Plant, excluding certain assets, and to pay AGR $20 million upon transfer, which WPCo will record as a regulatory asset, include in rate base and recover over the life of the plant. Additionally, the agreement stated that 82.5% of the costs associated with the acquired interest will be reflected in rates effective from the date of the transfer via a surcharge with an offset in ENEC revenues of $93 million. The remaining 17.5% of the costs associated with the acquired interest is to be included in rates by January 2020. The agreement also proposed that WPCo share the energy margins for 82.5% of the plant’s output with ratepayers and that WPCo retain all of the energy margins from sales into the wholesale market on the remaining 17.5%, to offset fixed costs associated with this portion, until the remaining portion is included in rates. In December 2014, the WVPSC issued an order that approved the settlement agreement, subject to certain modifications related to 82.5% of the energy and capacity margin sharing. The WVPSC determined that the sharing mechanism that was proposed is reasonable and will be adopted provided the result of the sharing mechanism will be adjusted, if necessary, so that the sharing mechanism does not result in a net cost to ratepayers that exceeds the actual variable cost of generation. In January 2015, the transfer of the one-half interest in the Mitchell Plant to WPCo was completed. See the “Plant Transfer” section of APCo Rate Matters in Note 4.

Kentucky Fuel Adjustment Clause Review

In August 2014, the KPSC issued an order initiating a review of KPCo's FAC from November 2013 through April 2014. In January 2015, the KPSC issued an order disallowing certain FAC costs during the period of January 2014 through May 2015 while KPCo owns and operates both Big Sandy Plant, Unit 2 and its one-half interest in the Mitchell Plant. Additionally, the KPSC directed KPCo to refund to customers $13 million of fuel costs, by the end of the second quarter of 2015, collected during the FAC review period of January 2014 through April 2014. As a result of this order, KPCo recorded a regulatory disallowance of $36 million in December 2014. In February 2015, KPCo filed an appeal of this order with the Franklin County Circuit Court.


7


2014 Kentucky Base Rate Case

In December 2014, KPCo filed a request with the KPSC for an increase in rates of $70 million, which consists of a $75 million increase in rider rates, offset by a $5 million decrease in annual base rates, to be effective July 2015. The net increase reflects KPCo's ownership interest in the Mitchell Plant, riders to recover the Big Sandy Plant retirement and operational costs and the inclusion of an environmental compliance plan related to the Mitchell Plant FGD. Additionally, the filing included a request to recover deferred storm costs. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

PJM Capacity Auction

AGR is required to offer all of its available generation capacity in the PJM RPM auction, which is conducted three years in advance of the actual delivery year.

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 capacity.  For non-switched OPCo generation customers, OPCo pays AGR its blended tariff rate for capacity consisting of $188.88/MW day for auctioned load and the non-fuel generation portion of its base rate for non-auctioned load.  AGR’s excess capacity is subject to the PJM RPM auction. After May 2015, AGR's generation assets will be subject to PJM capacity prices.  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

June 2017 through May 2018
 
120.00


We expect a significant decline in AGR capacity revenues after May 2015 when the Power Supply Agreement between AGR and OPCo ends. We expect a further decline in AGR capacity revenues from June 2016 through May 2017 based upon the decrease in the PJM base auction price.

In conjunction with other utility companies, we continue to address mutual concerns related to the PJM capacity auction process. Through this advocacy effort, the FERC has accepted PJM recommendations which should have the impact of reducing capacity price volatility beginning in the June 2018 time period.

In December 2014, PJM filed with FERC for approval of a new type of capacity product, the Capacity Performance Product. The intent of the filing is to raise the level of capacity performance and reliability during emergency events by: (a) assessing higher penalties for non-performance during these events, (b) allowing higher price offers into the auction and (c) requiring generating units to provide fuel and operational assurances that they can perform reliably during emergency events.

In this same filing, PJM proposed with FERC supplemental capacity auctions for the June 2016 through May 2017 and June 2017 through May 2018 auction periods. These supplemental auctions would address capacity performance and reliability issues in these interim years, and if accepted, would allow AGR to re-offer at least part of the capacity already cleared for these years at a higher price. A FERC order is expected in the first half of 2015.


8


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, 2014, SWEPCo has incurred costs of $164 million and has remaining contractual construction obligations of $108 million related to these projects.  SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. See "Climate Change, CO2 Regulation and Energy Policy" section of “Environmental Issues” below.  As of December 31, 2014, the net book value of Welsh Plant, Units 1 and 3 was $388 million, before cost of removal, including materials and supplies inventory and CWIP.  If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.   

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.  In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing.  We will continue to defend against the remaining 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, proposed clean water rules and renewal permits for certain water discharges that are currently under appeal.

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 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.

9


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.
 
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, 2014, 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, additional investment to meet these proposed requirements ranges from approximately $2.8 billion to $3.3 billion through 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 (SIPs) or federal implementation plans (FIPs) 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:
Company
 
Plant Name and Unit
 
Generating
Capacity
 
 
 
 
(in MWs)
AGR
 
Kammer Plant
 
630

AGR
 
Muskingum River Plant
 
1,440

AGR
 
Picway Plant
 
100

APCo
 
Clinch River Plant, Unit 3
 
235

APCo
 
Glen Lyn Plant
 
335

APCo
 
Kanawha River Plant
 
400

APCo/AGR
 
Sporn Plant
 
600

I&M
 
Tanners Creek Plant
 
995

KPCo
 
Big Sandy Plant, Unit 2
 
800

PSO
 
Northeastern Station, Unit 4
 
470

SWEPCo
 
Welsh Plant, Unit 2
 
528

Total
 
 
 
6,533


As of December 31, 2014, 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 regulated plants in the table above was $980 million.  See Note 5 for further discussion.

In addition, we are in the process of obtaining permits following the KPSC's approval for the conversion of KPCo's 278 MW Big Sandy Plant, Unit 1 to natural gas. As of December 31, 2014, the net book value, before cost of removal, including related material and supplies inventory and CWIP balances of Big Sandy Plant, Unit 1 was $114 million.


10


Volatility in fuel 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 the book value of 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 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.
 
The Federal EPA issued the Clean Air Interstate Rule (CAIR) in 2005 requiring specific reductions in SO2 and NOx emissions from power plants.  The Federal EPA issued the Cross-State Air Pollution Rule (CSAPR) in August 2011 to replace CAIR.  The CSAPR was challenged in the courts.  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 was appealed to the U.S. Supreme Court, which reversed the decision and remanded the case to the U.S. Court of Appeals for the District of Columbia Circuit.  All of the states in which our power plants are located are covered by CSAPR. See "Cross-State Air Pollution Rule (CSAPR)" section below.

The Federal EPA issued the final maximum achievable control technology (MACT) standards for coal and oil-fired power plants in 2012. See “Mercury and Other Hazardous Air Pollutants (HAPs) Regulation” section below.

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 SIPs or, if SIPs are not adequate or are not developed on schedule, through FIPs.  The Federal EPA proposed disapproval of SIPs in a few states, including Arkansas.  Arkansas 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.

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 and existing electric utility units. See "Climate Change, CO2 Regulation and Energy Policy" section below.

The Federal EPA has also issued final, more stringent national ambient air quality standards (NAAQS) for PM, SO2 and proposed a more stringent 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.

11


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.
 
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.  In 2012, the court issued a decision vacating and remanding CSAPR to the Federal EPA with instructions to continue implementing the CAIR 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 petition for review filed by the Federal EPA and other parties in the U.S. Supreme Court was granted in June 2013. In April 2014, the U.S. Supreme Court issued a decision reversing in part the decision of the U.S. Court of Appeals for the District of Columbia Circuit and remanding the case for further proceedings consistent with the opinion. The Federal EPA filed a motion to lift the stay and allow Phase I of CSAPR to take effect on January 1, 2015 and Phase II to take effect on January 1, 2017. The court granted the Federal EPA's motion, established a briefing schedule and scheduled oral argument for March 2015 on the remaining issues. Separate appeals of the Error Corrections Rule and the further revisions have been filed but no briefing schedules have been established. We cannot predict the outcome of the pending litigation.

Mercury and Other Hazardous Air Pollutants (HAPs) 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 metals) 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.  Petitions for administrative reconsideration and judicial review were 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. In April 2014, the U.S. Court of Appeals for the District of Columbia Circuit denied all of the petitions for review of the April 2012 final rule. Industry trade groups and several states filed petitions for further review in the U.S. Supreme Court and the court granted those petitions in November 2014.

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.  We have obtained a one-year administrative extension at several units to facilitate 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 remain concerned about the availability of compliance extensions, the inability to foreclose citizen suits being filed under the CAA for failure to achieve compliance by the required deadlines and the lack of coordination among the Mercury and Air Toxics Standards schedule and other environmental requirements.


12


Climate Change, CO2 Regulation and Energy Policy

National public policy makers and regulators in the 11 states we serve have diverse views on climate change, carbon regulation and energy policy.  We are currently focused on responding to these emerging views with prudent actions across a range of plausible scenarios and outcomes.  We are active participants in both state and federal policy development to assure that any proposed new requirements are feasible and the economies of the states we serve are not placed at a competitive disadvantage.

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 that can assist in reducing carbon emissions.  We are taking steps to comply with these requirements, including increasing our wind power purchases and broadening our portfolio of energy efficiency programs.

We estimate that our 2014 emissions were approximately 120 million metric tons.  This represents a reduction of 18% compared to our 2005 CO2 emissions of approximately 146 million metric tons.

In the absence of comprehensive federal climate change or energy policy legislation, 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 under the CAA.  The new proposal was issued in September 2013 and requires new large natural gas units to meet a limit of 1,000 pounds of CO2 per MWh of electricity generated and small natural gas units to meet a limit of 1,100 pounds of CO2 per MWh.  New coal-fired units are required to meet a limit of 1,100 pounds of CO2 per MWh, with the option to meet a 1,000 pound per MWh limit if they choose to average emissions over multiple years.  This proposal was published in the Federal Register in January 2014 and the comment period has closed.

The Federal EPA was also directed to develop and issue a separate proposal regulating carbon emissions from modified and reconstructed electric generating units (EGUs) and to issue guidelines for existing EGUs 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 Federal EPA issued guidelines for the development of standards for existing sources in June 2014. The guidelines use a “portfolio” approach to reducing emissions from existing sources that includes efficiency improvements at coal plants, displacing coal-fired generation with increased utilization of natural gas combined cycle units, expanding renewable generation resources and increasing customer energy efficiency. Comments were due in December 2014. The Federal EPA also issued proposed regulations governing emissions of CO2 from modified and reconstructed EGUs in June 2014 and comments were due in October 2014. The standards for modified and reconstructed units include several options, including use of historic baselines or energy efficiency audits to establish source-specific CO2 emission rates or to limit CO2 emission rates which could be no less than 1,900 pounds per MWh at larger coal units and 2,100 pounds per MWh at smaller coal units. The Federal EPA announced in January 2015 that the schedule for finalizing its action on all of these standards will extend into the summer of 2015 and that it will develop and propose for public comment a model FIP that will be finalized for individual states that fail to submit a timely state plan to implement the existing source standards. 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 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. In June 2014, the U.S. Supreme Court determined that the Federal EPA was not compelled to regulate CO2 emissions from stationary sources under the Title V or PSD programs as a result of its adoption of the motor vehicle standards, but that sources otherwise required to obtain a PSD permit may be required to perform a Best Available Control Technology analysis for CO2 emissions if they exceed a reasonable level. The Federal EPA must undertake additional rulemaking to implement the court’s decision and establish an appropriate level.


13


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.

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.

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 (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants.  The proposed rule contained 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 existing unlined surface impoundments.

Various environmental organizations and industry groups filed a petition seeking to establish deadlines for a final rule.  To comply with a court-ordered deadline, the Federal EPA issued a prepublication copy of its final rule in December 2014. The rule is expected to be published in the Federal Register during the first quarter of 2015 and become effective six months following publication.

In the final rule, the Federal EPA elected to regulate CCR as a non-hazardous solid waste and issued new minimum federal solid waste management standards. On the effective date, the rule applies to new and existing active CCR landfills and CCR surface impoundments at operating electric utility or independent power production facilities. The rule imposes new and additional construction and operating obligations, including location restrictions, liner criteria, structural integrity requirements for impoundments, operating criteria and additional groundwater monitoring requirements. The rule does not apply to inactive CCR landfills and inactive surface impoundments at retired generating stations or the beneficial use of CCR. The rule is self-implementing so state action is not required. Because of this self-implementing feature, the rule contains extensive record keeping, notice and internet posting requirements. Because we currently use surface impoundments and landfills to manage CCR materials at our generating facilities, we will incur significant costs to upgrade or close and replace these existing facilities at some point in the future as the new rule is implemented. We continue to review the new rule and evaluate its costs and impacts to our operations, including ongoing monitoring requirements.

In February 2014, the Federal EPA completed a risk evaluation of the beneficial uses of coal fly ash in concrete and FGD gypsum in 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.  Encapsulated beneficial uses are not materially impacted by the new rule but additional demonstrations may be required to continue land applications in significant amounts except in road construction projects.


14


Clean Water Act (CWA) Regulations

In 2014, the Federal EPA issued a final rule setting forth standards for existing power plants that is intended to 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 final rule affects all plants withdrawing more than two million gallons of cooling water per day. The rule offers seven technology options to comply with the impingement standard and requires site-specific studies to determine appropriate entrainment compliance measures at facilities withdrawing more than 125 million gallons per day. Additional requirements may be imposed as a result of consultation with other federal agencies to protect threatened and endangered species and their habitats. Facilities with existing closed cycle recirculating cooling systems, as defined in the rule, are not expected to require any technology changes. Facilities subject to both the impingement standard and site-specific entrainment studies will typically be given at least three years to conduct and submit the results of those studies to the permit agency. Compliance timeframes will then be established by the permit agency through each facility’s National Pollutant Discharge Elimination System (NPDES) permit for installation of any required technology changes, as those permits are renewed over the next five to eight years. Petitions for review of the final rule have been filed by industry and environmental groups and are currently pending in the U.S. Court of Appeals for the Second Circuit.

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 September 2015.  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.

In April 2014, the Federal EPA and the U.S. Army Corps of Engineers jointly issued a proposed rule to clarify the scope of the regulatory definition of “waters of the United States” in light of recent U.S. Supreme Court cases and published the proposed rule in the Federal Register. The CWA provides for federal jurisdiction over “navigable waters” defined as “the waters of the United States.” This proposed jurisdictional definition will apply to all CWA programs, potentially impacting generation, transmission and distribution permitting and compliance requirements. Among those programs are: permits for wastewater and storm water discharges, permits for impacts to wetlands and water bodies and oil spill prevention planning. We agree that clarity and efficiency in the permitting process is needed. We are concerned that the proposed rule introduces new concepts and could subject more of our operations to CWA jurisdiction, thereby increasing the time and complexity of permitting. We submitted detailed comments to the Federal EPA in November 2014 and also participated in comments filed by various organizations of which we are members.

15


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.

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 to serve SSO customers, and provides capacity for all connected load.

AEP Transmission Holdco

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

Generation & Marketing

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

AEP River Operations

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


16


The table below presents Earnings Attributable to AEP Common Shareholders by segment for the years ended December 31, 2014, 2013 and 2012.
 
 
Years Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(in millions)
Vertically Integrated Utilities
 
$
708

 
$
677

 
$
800

Transmission and Distribution Utilities
 
355

 
358

 
389

AEP Transmission Holdco
 
151

 
80

 
43

Generation & Marketing
 
367

 
228

 
100

AEP River Operations
 
49

 
12

 
15

Corporate and Other (a)
 
4

 
125

 
(88
)
Earnings Attributable to AEP Common Shareholders
 
$
1,634

 
$
1,480

 
$
1,259


(a)
While not considered a reportable segment, Corporate and Other primarily includes 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.

AEP CONSOLIDATED

2014 Compared to 2013

Earnings Attributable to AEP Common Shareholders increased from $1,480 million in 2013 to $1,634 million in 2014 primarily due to:

Impairments during 2013 for the following:
Muskingum River Plant, Unit 5.
A decision from the KPSC disallowing scrubber costs on KPCo's Big Sandy Plant.
A net increase in weather-related usage.
Higher market prices and increased sales volumes.
An increase in transmission investment which resulted in higher revenues and income.
Successful rate proceedings during 2014 in our various jurisdictions.

These increases were partially offset by:

A favorable U.K. Windfall Tax decision by the U.S. Supreme Court in 2013.
An increase in depreciation expense due to increased investments.
An increase in regulatory provisions in 2014.
An increase in fuel expense due to the termination of a long-term coal contract.
An increase in plant maintenance.
An increase in vegetation management expenses.


17


2013 Compared to 2012

Earnings Attributable to AEP Common Shareholders increased from $1,259 million in 2012 to $1,480 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.

Our results of operations by operating segment are discussed below.

VERTICALLY INTEGRATED UTILITIES
 
 
Years Ended December 31,
Vertically Integrated Utilities
 
2014
 
2013
 
2012
 
 
(in millions)
Revenues
 
$
9,484

 
$
9,992

 
$
9,418

Fuel and Purchased Electricity
 
3,953

 
4,770

 
4,408

Gross Margin
 
5,531

 
5,222

 
5,010

Other Operation and Maintenance
 
2,515

 
2,276

 
2,219

Asset Impairments and Other Related Charges
 

 
72

 
13

Depreciation and Amortization
 
1,033

 
941

 
873

Taxes Other Than Income Taxes
 
370

 
372

 
344

Operating Income
 
1,613

 
1,561

 
1,561

Interest and Investment Income
 
4

 
7

 
5

Carrying Costs Income
 
6

 
14

 
28

Allowance for Equity Funds Used During Construction
 
47

 
35

 
72

Interest Expense
 
(526
)
 
(540
)
 
(520
)
Income Before Income Tax Expense and Equity Earnings
 
1,144

 
1,077

 
1,146

Income Tax Expense
 
434

 
398

 
345

Equity Earnings of Unconsolidated Subsidiaries
 
2

 
2

 
2

Net Income
 
712

 
681

 
803

Net Income Attributable to Noncontrolling Interests
 
4

 
4

 
3

Earnings Attributable to AEP Common Shareholders
 
$
708

 
$
677

 
$
800


18


Summary of KWh Energy Sales for Vertically Integrated Utilities
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2014
 
2013
 
2012
 
 
 
(in millions of KWhs)
 
Retail:
 
 
 
 
 
 
 
Residential
 
34,073

 
33,851

 
33,199

 
Commercial
 
25,048

 
25,037

 
25,278

 
Industrial
 
35,281

 
34,216

 
34,692

 
Miscellaneous
 
2,311

 
2,284

 
2,356

 
Total Retail
 
96,713

 
95,388

 
95,525

 
 
 
 
 
 
 
 
 
Wholesale (a)
 
34,241

 
NM

(b)
NM

(b)
 
 
 
 
 
 
 
 
Total KWhs
 
130,954

 
95,388

 
95,525

 

(a)
Includes off-system sales, municipalities and cooperatives, unit power and other wholesale customers.
(b)
2014 is not comparable to 2013 or 2012 due to the 2013 asset transfers related to corporate separation in Ohio on December 31, 2013 and the termination of the Interconnection Agreement effective January 1, 2014.
NM    Not meaningful.

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,
 
 
2014
 
2013
 
2012
 
 
(in degree days)
Eastern Region
 
 
 
 
 
 
Actual – Heating (a)
 
3,313

 
2,949

 
2,216

Normal – Heating (b)
 
2,740

 
2,734

 
2,774

 
 
 
 
 
 
 
Actual – Cooling (c)
 
932

 
1,040

 
1,253

Normal – Cooling (b)
 
1,080

 
1,080

 
1,079

 
 
 
 
 
 
 
Western Region
 
 
 
 
 
 
Actual – Heating (a)
 
1,840

 
1,772

 
1,070

Normal – Heating (b)
 
1,510

 
1,501

 
1,537

 
 
 
 
 
 
 
Actual – Cooling (c)
 
2,049

 
2,163

 
2,635

Normal – Cooling (b)
 
2,203

 
2,202

 
2,186


(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.

19


2014 Compared to 2013
 
Reconciliation of Year Ended December 31, 2013 to Year Ended December 31, 2014
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
Year Ended December 31, 2013
 
$
677

 
 
 
Changes in Gross Margin:
 
 
Retail Margins
 
212

Off-system Sales
 
123

Transmission Revenues
 
22

Other Revenues
 
(48
)
Total Change in Gross Margin
 
309

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(239
)
Asset Impairments and Other Related Charges
 
72

Depreciation and Amortization
 
(92
)
Taxes Other Than Income Taxes
 
2

Interest and Investment Income
 
(3
)
Carrying Costs Income
 
(8
)
Allowance for Equity Funds Used During Construction
 
12

Interest Expense
 
14

Total Change in Expenses and Other
 
(242
)
 
 
 
Income Tax Expense
 
(36
)
 
 
 
Year Ended December 31, 2014
 
$
708


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 $212 million primarily due to the following:

The effect of successful rate proceedings in our service territories, which include:
 
 
A $129 million rate increase for APCo.
 
 
A $55 million rate increase for KPCo.
 
 
A $45 million rate increase for I&M.
 
 
A $22 million rate increase for SWEPCo.
 
 
A $12 million rate increase for PSO.
 
 
A $9 million rate increase for WPCo.
 
For the rate increases described above, $153 million relates to riders/trackers which have corresponding increases in other expense items below.
 
A $14 million increase due to favorable weather conditions.
 
These increases were partially offset by:
 
A $43 million increase in PJM expenses net of recovery or offsets.
 
A $36 million decrease due to a fuel proceeding disallowance.
Margins from Off-system Sales increased $123 million primarily due to higher market prices and changes in margin sharing.
Transmission Revenues increased $22 million primarily due to increased investment in the PJM region.
Other Revenues decreased $48 million primarily due to a decrease in barging because River Transportation Division (RTD) is no longer serving plants transferred from OPCo to AGR as of December 31, 2013 as a result of corporate separation in Ohio. This decrease in RTD revenue has a corresponding decrease in Other Operation and Maintenance expenses for barging as discussed below.


20


Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $239 million primarily due to the following:
 
A $56 million increase in recoverable expenses, primarily including PJM expenses, currently fully recovered in rate recovery riders/trackers, partially offset by RTD expenses for barging activities.
 
A $46 million increase in employee related expenses.
 
A $45 million increase in transmission services related to PJM and SPP services.
 
A $43 million increase in plant outage and maintenance expense primarily due to higher planned and advanced spending.
 
A $26 million increase in distribution and transmission vegetation management expenses primarily due to higher advanced spending.
 
A $25 million increase due to a favorable settlement of an insurance claim in the first quarter of 2013.
 
A $10 million increase due to the write-off of IGCC costs in Virginia.
 
An $8 million increase due to an accrual for future environmental remediation costs.
 
These increases were partially offset by:
 
A $30 million write-off in the first quarter of 2013 of previously deferred 2012 Virginia storm costs resulting from the 2013 enactment of a Virginia law.
 
A $23 million decrease in storm expense primarily in the APCo service territory.
Asset Impairments and Other Related Charges decreased $72 million primarily due to the following:
 
A $39 million decrease 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 decrease due to KPCo's 2013 write-off of scrubber costs on the Big Sandy Plant and other generation costs in accordance with the KPSC's October 2013 order.
Depreciation and Amortization expenses increased $92 million primarily due to higher depreciable base.
Carrying Cost Income decreased $8 million primarily due to the November 2013 securitization of the West Virginia ENEC deferral balance.
Allowance for Equity Funds Used During Construction increased $12 million primarily due to increases in environmental construction and transmission projects.
Interest Expense decreased $14 million primarily due to the following:
 
A $6 million decrease due to the retirement of KPCo Senior Unsecured Notes in the third quarter of 2013.
 
A $4 million decrease due to the redemption of I&M Senior Unsecured Notes in the fourth quarter of 2013.
 
A $4 million decrease due to rate approvals in Louisiana and Texas as well as an increase in the debt component of AFUDC due to increased transmission and environmental projects.
Income Tax Expense increased $36 million primarily due to an increase in pretax book income, the recording of state income tax adjustments and other book/tax differences which are accounted for on a flow-through basis, partially offset by the recording of federal income tax adjustments.


21


2013 Compared to 2012
 
Reconciliation of Year Ended December 31, 2012 to Year Ended December 31, 2013
Earnings Attributable to AEP Common Shareholders from Vertically Integrated Utilities
(in millions)
Year Ended December 31, 2012
 
$
800

 
 
 
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
)
Net Income Attributable to Noncontrolling Interests
 
(1
)
 
 
 
Year Ended December 31, 2013
 
$
677


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.

22


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 partially offset by Other Operation and Maintenance expenses below.

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 the 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, partially offset by a decrease in pretax book income.


23


TRANSMISSION AND DISTRIBUTION UTILITIES
 
 
Years Ended December 31,
Transmission and Distribution Utilities
 
2014
 
2013
 
2012
 
 
(in millions)
Revenues
 
$
4,814

 
$
4,478

 
$
4,818

Purchased Electricity
 
1,520

 
1,627

 
2,071

Amortization of Generation Deferrals
 
111

 

 

Gross Margin
 
3,183

 
2,851

 
2,747

Other Operation and Maintenance
 
1,276

 
1,003

 
911

Depreciation and Amortization
 
658

 
591

 
561

Taxes Other Than Income Taxes
 
453

 
435

 
428

Operating Income
 
796

 
822

 
847

Interest and Investment Income
 
11

 
2

 
4

Carrying Costs Income
 
27

 
16

 
24

Allowance for Equity Funds Used During Construction
 
12

 
8

 
6

Interest Expense
 
(280
)
 
(292
)
 
(291
)
Income Before Income Tax Expense
 
566

 
556

 
590

Income Tax Expense
 
211

 
198

 
201

Net Income
 
355

 
358

 
389

Net Income Attributable to Noncontrolling Interests
 

 

 

Earnings Attributable to AEP Common Shareholders
 
$
355

 
$
358

 
$
389

Summary of KWh Energy Sales for Transmission and Distribution Utilities
 
 
 
 
 
 
 
 
 
 
 
Years Ended December 31,
 
 
 
2014
 
2013
 
2012
 
 
 
(in millions of KWhs)
 
Retail:
 
 
 
 
 
 
 
Residential
 
26,209

 
25,531

 
25,581

 
Commercial
 
25,307

 
24,631

 
24,746

 
Industrial
 
21,830

 
22,668

 
24,902

 
Miscellaneous
 
713

 
710

 
716

 
Total Retail (a)
 
74,059

 
73,540

 
75,945

 
 
 
 
 
 
 
 
 
Wholesale (b)
 
2,198

 
NM

(c)
NM

(c)
 
 
 
 
 
 
 
 
Total KWhs
 
76,257

 
73,540

 
75,945

 

(a)
Represents energy delivered to distribution customers.
(b)
Ohio's contractually obligated purchases of OVEC power sold into PJM.
(c)
2014 is not comparable to 2013 or 2012 due to the 2013 asset transfers related to corporate separation in Ohio on December 31, 2013 and the termination of the Interconnection Agreement effective January 1, 2014.
NM    Not meaningful.


24


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,
 
 
2014
 
2013
 
2012
 
 
(in degree days)
Eastern Region
 
 
 
 
 
 
Actual – Heating (a)
 
3,734

 
3,383

 
2,610

Normal – Heating (b)
 
3,230

 
3,229

 
3,276

 
 
 
 
 
 
 
Actual – Cooling (c)
 
949

 
1,029

 
1,248

Normal – Cooling (b)
 
960

 
954

 
948

 
 
 
 
 
 
 
Western Region
 
 
 
 
 
 
Actual – Heating (a)
 
428

 
368

 
177

Normal – Heating (b)
 
337

 
337

 
352

 
 
 
 
 
 
 
Actual – Cooling (d)
 
2,553

 
2,737

 
3,100

Normal – Cooling (b)
 
2,618

 
2,608

 
2,584


(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.

25


2014 Compared to 2013
 
Reconciliation of Year Ended December 31, 2013 to Year Ended December 31, 2014
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(in millions)
Year Ended December 31, 2013
 
$
358

 
 
 
Changes in Gross Margin:
 
 
Retail Margins
 
236

Off-System Sales
 
3

Transmission Revenues
 
71

Other Revenues
 
22

Total Change in Gross Margin
 
332

 
 
 
Changes in Expenses and Other:
 
 
Other Operation and Maintenance
 
(273
)
Depreciation and Amortization
 
(67
)
Taxes Other Than Income Taxes
 
(18
)
Interest and Investment Income
 
9

Carrying Costs Income
 
11

Allowance for Equity Funds Used During Construction
 
4

Interest Expense
 
12

Total Change in Expenses and Other
 
(322
)
 
 
 
Income Tax Expense
 
(13
)
 
 
 
Year Ended December 31, 2014
 
$
355


The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity and amortization of generation deferrals were as follows:
Retail Margins increased $236 million primarily due to the following:
 
A $106 million increase in revenues primarily associated with Ohio rate riders/trackers and PJM revenues, partially offset by regulatory provisions.  These increases have corresponding increases in expense items discussed below.
 
A $96 million increase in TCC and TNC revenues primarily due to the recovery of ERCOT transmission expenses which is offset in Other Operation and Maintenance below.
Transmission Revenues increased $71 million primarily due to:

A $58 million increase primarily due to increased transmission revenues from customers who have switched to alternative CRES providers, rate increases for customers in the PJM region and increased transmission investment. This increase in transmission revenues related to CRES providers primarily offsets lost revenues included in Retail Margins above.
 
A $14 million increase primarily due to increased transmission investment in ERCOT.
Other Revenues increased $22 million primarily due to an increase in Texas securitization revenues which is offset in Depreciation and Amortization and Interest Expense below.


26


Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $273 million primarily due to the following:

A $213 million increase in recoverable expenses, including PJM expenses, ERCOT expenses and the Ohio storm amortization, currently fully recovered in rate recovery riders/trackers.
 
A $19 million increase in expenses related to various distribution services as a result of advanced spending.

An $18 million increase in remitted Universal Service Fund (USF) surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase is offset by an increase in Retail Margins above.
 
A $9 million increase in vegetation management expenses primarily due to advanced spending.
Depreciation and Amortization expenses increased $67 million primarily due to the following:
 
A $39 million increase in amortization related to OPCo and TCC securitizations, which are partially offset in Retail Margins and Other Revenues above.
 
A $28 million increase due to an increase in the depreciable base of transmission and distribution assets.
Taxes Other Than Income Taxes increased $18 million primarily due to increased property taxes.
Interest and Investment Income increased $9 million primarily due to interest on affiliated notes resulting from corporate separation.
Carrying Costs Income increased $11 million primarily due to increased capacity deferral carrying charges.
Interest Expense decreased $12 million primarily due to reduced TCC securitization long-term debt outstanding, which is partially offset in Other Revenues above.
Income Tax Expense increased $13 million primarily due to an increase in pretax book income and by the recording of federal and state income tax adjustments.

27


2013 Compared to 2012
 
Reconciliation of Year Ended December 31, 2012 to Year Ended December 31, 2013
Earnings Attributable to AEP Common Shareholders from Transmission and Distribution Utilities
(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
 
(1
)
Total Change in Expenses and Other
 
(138
)
 
 
 
Income Tax Expense
 
3

 
 
 
Year Ended December 31, 2013
 
$
358


The major components of the increase in Gross Margin, defined as revenues less the related direct cost of purchased electricity were as follows:
Retail Margins increased $55 million primarily due to the following:
 
A $123 million increase in revenues associated with OPCo's USF surcharge and Distribution Investment Recovery Rider.  A portion of these increases have corresponding increases in other expense items below.
 
A $17 million increase related to favorable regulatory proceedings for OPCo.
 
These increases were partially offset by:
 
A $40 million decrease related to Ohio customers switching to alternative CRES providers.  This decrease in Retail Margins is partially offset by an increase in Transmission Revenues related to CRES providers detailed below.
 
A $35 million decrease due to OPCo's partial reversal in 2012 of a 2011 fuel provision related to CRES providers.
Transmission Revenues increased $46 million primarily due to increased transmission revenues from Ohio customers who switched to alternative CRES providers.


28


Expenses and Other and Income Tax Expense changed between years as follows:
Other Operation and Maintenance expenses increased $92 million primarily due to the following:
 
An $86 million increase in remitted USF surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers.  This increase was offset by a corresponding increase in Retail Margins above.
 
A $30 million net increase related to the 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 the Ohio modified stipulation and the PUCO's August 2012 approval of the June 2012-May 2015 ESP.
 
These increases were partially offset by:
 
A $14 million decrease in expenses related to the 2012 sustainable cost reductions.
 
A $13 million decrease in Ohio's gridSMART® expenses primarily due to a reduction in the operation and maintenance component of the gridSMART® rider for prior years' over collections.  This decrease was partially offset by a corresponding increase in Depreciation and Amortization.
Depreciation and Amortization expenses increased $30 million primarily due to the following:
 
An $8 million increase due to OPCo's and TCC's issuance of securitization bonds in August 2013 and March 2012, respectively.  This increase in OPCo's and TCC's securitization related amortizations are offset within Gross Margin.
 
A $7 million increase due to increased investment in distribution and transmission plant.
 
A $4 million increase in Ohio's gridSMART® expenses primarily due to an increase in the depreciation component of the gridSMART® rider to recover prior years' under collections.  This increase was offset by a corresponding decrease in Operation and Maintenance expenses above.
Taxes Other Than Income Taxes increased $7 million primarily due to increased property taxes.
Carrying Costs Income decreased $8 million primarily due to the first quarter 2012 recording of debt carrying costs prior to TCC's issuance of securitization bonds in March 2012.
Income Tax Expense decreased $3 million primarily due to a decrease in pretax book income, partially offset by the recording of state income tax adjustments.
 

29


AEP TRANSMISSION HOLDCO


Years Ended December 31,
AEP Transmission Holdco

2014

2013

2012


(in millions)
Transmission Revenues

$
192


$
78


$
24

Gross Margin

192


78


24

Other Operation and Maintenance

29


12


9

Depreciation and Amortization

24


10


3

Taxes Other Than Income Taxes

32


20


5

Operating Income

107


36


7

Carrying Costs Income
 

 

 
1

Allowance for Equity Funds Used During Construction

45


30


14

Interest Expense

(23
)

(10
)

(3
)
Income Before Income Tax Expense

129


56


19

Income Tax Expense

63


29


17

Equity Earnings of Unconsolidated Subsidiaries

85


53


41

Net Income

151


80


43

Net Income Attributable to Noncontrolling Interests






Earnings Attributable to AEP Common Shareholders

$
151


$
80


$