|
|
 | | | |
- close
- close
- close
- close
| |||||||||
American Electric Power Company 10-K 2007 Documents found in this filing:
2006
Annual Reports
American
Electric Power Company, Inc.
AEP
Generating Company
AEP
Texas
Central Company
AEP
Texas
North Company
Appalachian
Power Company
Columbus
Southern Power Company
Indiana
Michigan Power Company
Kentucky
Power Company
Ohio
Power Company
Public
Service Company of Oklahoma
Southwestern
Electric Power Company
Audited
Financial Statements and
Management’s
Financial Discussion and Analysis
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX
TO ANNUAL REPORTS
GLOSSARY
OF TERMS
When
the following terms and abbreviations appear in the text of this report, they
have the meanings indicated below.
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. Although AEP and each of its Registrant Subsidiaries believe that their
expectations are based on reasonable assumptions, any such statements may be
influenced by factors that could cause actual outcomes and results to be
materially different from those projected. Among the factors that could cause
actual results to differ materially from those in the forward-looking statements
are:
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:
AEP
common stock is traded principally on the New York Stock Exchange. At December
31, 2006, AEP had approximately 112,000 registered shareholders.
SELECTED
CONSOLIDATED FINANCIAL DATA
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT’S
FINANCIAL DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS
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.
We
operate an extensive portfolio of assets including:
EXECUTIVE
OVERVIEW
BUSINESS
STRATEGY
Our
mission is to bring comfort to our customers, support business and commerce
and
build strong communities. We invest in our core utility business operations
to
execute our mission. Our objective is to be an economical, reliable and safe
provider of electric energy to the markets that we serve. We plan to buy or
build additional generation to meet franchise service obligations. Our plan
entails designing, building, improving and operating reasonably priced,
environmentally-compliant, efficient sources of power and maximizing the amount
of power delivered from these facilities. We intend to maintain and enhance
our
position as a safe and reliable provider of electric energy by making
significant investments in environmental and reliability upgrades. We will
seek
to recover the cost of our new utility investments in a manner that results
in
reasonable rates for our customers while providing a fair return for our
shareholders through a stable stream of cash flows, enabling us to pay
dependable, competitive dividends. We operate our generating assets to maximize
our productivity and profitability after meeting our native load
requirements.
In
summary, our business strategy is to:
OUTLOOK
FOR 2007
We
remain
focused on the fundamental earning power of our utilities and committed to
maintaining our credit quality. To achieve our goals we plan to:
There
are, nevertheless, certain risks and challenges including:
Regulatory
Activity
In
2007,
our significant regulatory activities will include:
Fuel
Costs
During
2006, spot market prices for coal and natural gas declined. In contrast, market
prices for fuel oil increased and continue to be volatile. We still experienced
an eight percent increase in coal costs during 2006 and expect a seven to nine
percent increase in 2007 even considering softening fuel markets and favorable
transportation effects during the year. The increase is primarily due to
expiring lower priced contracts being replaced with new higher priced contracts.
We have price risk related to these commodity prices. We do not have an active
fuel cost recovery adjustment mechanism in Ohio, which represents approximately
20% of our fuel costs. In Indiana, our fuel recovery mechanism is temporarily
capped, subject to preestablished escalators, at a fixed rate through June
2007.
As a consequence of the cap, we incurred under-recoveries of $26 million for
2006 and expect additional under-recoveries through June 2007.
Our
Ohio
companies increased their generation rates in 2006, as previously approved
by
the PUCO in our Rate Stabilization Plans. These increased rates, along with
the
reinstated fuel cost adjustment rate clause for over- or under-recovery of
fuel,
off-system sales margins, certain transmission items and related costs effective
July 1, 2006 in West Virginia, will help offset future negative impacts of
fuel
price increases on our gross margins.
Capital
Expenditures
Our
current projections call for capital expenditures of approximately $9.9 billion
from 2007-2009. For 2007, we forecast approximately $3.5 billion in construction
expenditures, excluding allowances for funds used during construction. We also
forecast purchases of additional gas-fired generating units for a total of
$427
million. Our current projections are as follows:
Off-System
Sales
In
2007,
we expect a decline in off-system sales revenues less the related direct cost
of
fuel, including consumption of chemicals and emissions allowances, and purchased
power. This decline is primarily due to expected increases in sales to municipal
and energy cooperative customers and demand for electricity from our native
load
retail customers including Ormet, which reduces the amount of power available
for off-system sales. In addition, lower expected generating plant availability
due to environmental retrofit outages likely will result in lower off-system
sales.
Corporate
Sustainability Reporting
Our
first
Corporate Responsibility report will be published and available in 2007. In
2004
a subcommittee of the Policy Committee of our Board of Directors prepared a
report entitled, “An Assessment of AEP’s Actions to Mitigate the Economic
Impacts of Emissions Policies.” While the 2004 report was quite well received,
it primarily addressed environmental issues we face. The scope of our 2007
report will reach beyond environmental issues and address other matters that
create risk to our sustainability into the future. The report will be developed
using the sustainability reporting guidelines issued by the Global Reporting
Initiative and will address issues such as leadership, strategy and management,
workforce issues including safety and health, climate change and energy
security, reliability and growth.
2006
RESULTS
We
had a
year of continued improvement and many accomplishments in 2006. Our total
shareholder return was 18.8% and we increased our quarterly dividend 5.4% to
$0.39 per share.
We
continued receiving favorable outcomes in various regulatory activities
resulting in increased revenues. We continued securing new power supply
contracts with municipal and cooperative customers and our barging subsidiary
produced strong results. Some of these positive factors were offset in part
by
mild weather and an impairment loss from the sale of the Plaquemine Cogeneration
Facility to Dow Chemical Company.
We
announced plans for new generation in Oklahoma, Louisiana and Arkansas;
continued work on engineering and design on new clean-coal plants in Ohio and
West Virginia; announced a proposal to build a 550-mile, 765-kilovolt
transmission line from West Virginia to New Jersey to address west-east power
flow and congestion issues in PJM; announced a joint venture with MidAmerican
to
build much needed transmission capacity in Texas and we agreed to purchase
additional gas-fired generating plants in 2007 to address capacity concerns
in
the east.
Our
regulatory accomplishments include the implementation of new base rates in
Ohio,
Kentucky, West Virginia and Virginia (subject to refund) and we have taken
a
step forward in resolving the rate design issues related to our FERC
transmission rates. Although various legal issues remain to be decided, we
received a final order in our Texas True-up Proceeding and in October 2006
we
received proceeds of $1.7 billion related to the securitization of our Texas
regulatory assets. We received approval for our request to increase rates for
recovery of incremental environmental and reliability costs in
Virginia.
RESULTS
OF OPERATIONS
Segments
Our
primary business strategy and the core of our business focus on our electric
utility operations. Within our Utility Operations segment, we centrally dispatch
all generation assets and manage our overall utility operations on an integrated
basis because of the substantial impact of cost-based rates and regulatory
oversight. Generation/supply in Ohio and Virginia continue to have
commission-determined transition rates. Virginia is currently considering
returning to regulation for generation. While our Utility Operations segment
remains our primary business segment, the emergence of other areas of our
business prompted us to identify two new business segments in 2006. One of
these
new segments is our MEMCO Operations segment, which reflects our significant
ongoing barging activities. We also identified our Generation and Marketing
segment, which includes
our nonregulated generating, marketing and risk management activities in the
ERCOT market area. We
no
longer consider Investments - Gas Operations and Investments - UK Operations
as
reportable segments because we have sold substantially all of those
assets.
Starting
in the fourth quarter of 2006, our new segments and their related business
activities are as follows:
Utility
Operations
MEMCO
Operations
Generation
and Marketing
The
table
below presents our consolidated Income Before Discontinued Operations,
Extraordinary Loss and Cumulative Effect of Accounting Change for the years
ended December 31, 2006, 2005 and 2004 (Earnings and Weighted Average Number
of
Basic Shares Outstanding in millions). We reclassified prior year amounts to
conform to the current year’s presentation.
2006
Compared to 2005
Income
Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of
Accounting Change in 2006 decreased $37 million compared to 2005 primarily
due
to a $136 million after-tax impairment recorded in the third quarter of 2006
related to the sale of the Plaquemine Cogeneration Facility offset by a $59
million increase in MEMCO Operations earnings. Utility Operations earnings
increased $10 million due to new retail rates implemented in Ohio, Kentucky,
Oklahoma, Virginia and West Virginia mostly offset by unfavorable weather,
decreases in transmission revenues from the loss of SECA rates and increases
in
regulatory amortization and operating expenses.
Average
basic shares outstanding increased to 394 million in 2006 from 390 million
in
2005 primarily due to the issuance of shares under our incentive compensation
and dividend reinvestment plans. Actual shares outstanding were 397
million as of December 31, 2006.
2005
Compared to 2004
Income
Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of
Accounting Change in 2005 decreased $98 million compared to 2004 primarily
due
to gains on sales of equity investments in 2004 and a decrease in recorded
stranded generation carrying costs income in 2005, as a result of the PUCT
decisions related to TCC’s True-up Proceeding.
Average
basic shares outstanding decreased to 390 million in 2005 from 396 million
in
2004 primarily due to the common stock share repurchase program executed in
2005. Actual shares outstanding were 394 million as of December 31,
2005.
Our
results of operations are discussed below according to our operating
segments.
Utility
Operations
Our
Utility Operations include primarily regulated revenues with direct and variable
offsetting expenses and net reported commodity trading operations. We believe
that a discussion of the results from our Utility Operations segment on a gross
margin basis is most appropriate in order to further understand the key drivers
of the segment. Gross margin represents utility operating revenues less the
related direct cost of fuel, including consumption of chemicals and emissions
allowances, and purchased power.
Summary
of Selected Sales and Weather Data
For
Utility Operations
For
the Years Ended December 31, 2006, 2005 and 2004
Cooling
degree days and heating degree days are metrics commonly used in the utility
industry as a measure of the impact of weather on results of operations. In
general, degree day changes in our eastern region have a larger effect on
results of operations than changes in our western region due to the relative
size of the two regions and the associated number of customers within each.
Cooling degree days and heating degree days in our service territory for the
years ended December 31, 2006, 2005 and 2004 were as follows:
2006
Compared to 2005
Reconciliation
of Year Ended December 31, 2005 to Year Ended December 31,
2006
Income
from Utility Operations Before Discontinued Operations, Extraordinary Loss
and
Cumulative
Effect of Accounting Change
(in
millions)
Income
from Utility Operations Before Discontinued Operations, Extraordinary Loss
and
Cumulative Effect of Accounting Change increased $10 million to $1,028 million
in 2006. The key driver of the increase was a $241 million increase in Gross
Margin offset by a $163 million increase in Operating Expenses and Other and
a
$68 million increase in Income Tax Expense.
The
major
components of the net increase in Gross Margin were as follows:
Utility
Operating Expenses and Other and Income Taxes changed between years as follows:
2005
Compared to 2004
Reconciliation
of Year Ended December 31, 2004 to Year Ended December 31,
2005
Income
from Utility Operations Before Discontinued Operations, Extraordinary Loss
and
Cumulative
Effect of Accounting Change
(in
millions)
Income
from Utility Operations Before Discontinued Operations, Extraordinary Loss
and
Cumulative Effect of Accounting Change decreased $157 million to $1,018 million
in 2005. Key driver of the decrease included a $281 million increase in
Operating Expenses and Other, offset in part by a $41 million increase in Gross
Margin and an $83 million decrease in Income Tax Expense.
The
major
components of the net increase in Gross Margin were as follows:
Utility
Operating Expenses and Other changed between years as follows:
MEMCO
Operations
2006
Compared to 2005
Income
Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of
Accounting Change from our MEMCO Operations segment increased from $21 million
in 2005 to $80 million in 2006. The increase was primarily related to strong
demand and a tight supply of barges resulting in increased barge freight rates
and utilization. Additionally, 2006 operating conditions for our barging
operations improved from 2005 when hurricanes, severe ice and flooding caused
increased operating costs.
2005
Compared to 2004
Income
Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of
Accounting Change from our MEMCO Operations segment increased from $12 million
in 2004 to $21 million in 2005. The increase was primarily related to favorable
barging activity due to strong demand and a tight supply of barges, resulting
in
a 45% increase in freight rates between 2004 and 2005.
Generation
and Marketing
2006
Compared to 2005
Income
Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of
Accounting Change from our Generation and Marketing segment in 2006 was
essentially flat when compared to 2005.
2005
Compared to 2004
Income
Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of
Accounting Change from our Generation and Marketing segment decreased from
$73
million in 2004 to $16 million in 2005. The decrease was primarily due to a
$64
million after-tax gain on the sale of our equity investments in the Colorado
and
Florida independent power producers in 2004.
All
Other
2006
Compared to 2005
Loss
Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of
Accounting Change from All Other increased from a $26 million loss in 2005
to a
$128 million loss in 2006. The increase primarily relates to the $136 million
after-tax impairment recorded in the third quarter of 2006 related to the sale
of the Plaquemine Cogeneration Facility, partially offset by lower interest
expense and associated buyback costs related to the redemption of $550 million
of senior unsecured notes in April 2005.
2005
Compared to 2004
Loss
Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of
Accounting Change decreased from a $133 million loss in 2004 to a $26 million
loss in 2005. The 2005 results include only one-month of HPL’s operations
compared to a full year of HPL operations in 2004 due to the sale of HPL in
January of 2005. We also resolved a portion of our outstanding Enron litigation
in 2005 resulting in a net of tax settlement cost of approximately $28
million.
AEP
System Income Taxes
Income
Tax Expense increased $55 million between 2005 and 2006 primarily due to an
increase in pretax book income, state income taxes and changes in certain
book/tax differences accounted for on a flow-through basis and the recording
of
tax reserve adjustments.
Income
Tax Expense decreased $142 million between 2004 and 2005 primarily due to a
decrease in pretax book income, state income taxes and changes in certain
book/tax differences accounted for on a flow-through basis, offset in part
by
the recording of the tax return adjustments.
FINANCIAL
CONDITION
We
measure our financial condition by the strength of our balance sheet and the
liquidity provided by our cash flows. During 2006, we maintained our strong
financial condition as reflected by the following actions and
events:
Debt
and Equity Capitalization
($ in millions)
As
a
consequence of the capital changes during 2006, primarily the issuance of the
securitization bonds and the adoption of SFAS 158, our ratio of debt to total
capital increased from 57.2% to 59.1%.
In
September 2006, the FASB issued SFAS 158 related to phase one of its pension
and
postretirement benefit accounting project. The new standard requires the
recognition of a liability for pension and postretirement benefit plans, thereby
eliminating on the balance sheet the SFAS 87 and SFAS 106 deferral and
amortization of net actuarial gains and losses. The adoption during the fourth
quarter of 2006 resulted in a negative impact on our common equity at December
31, 2006 due to the recognition of a $235 million net of tax accumulated other
comprehensive income reduction to common equity for those jurisdictions where
we
could not record a regulatory asset.
Liquidity
Liquidity,
or access to cash, is an important factor in determining our financial
stability. We are committed to maintaining adequate liquidity.
Credit
Facilities
We
manage
our liquidity by maintaining adequate external financing commitments. At
December 31, 2006, our available liquidity was approximately $3.3 billion as
illustrated in the table below:
In
2006,
we amended the terms and increased the size of our credit facilities from $2.7
billion to $3 billion on terms more economically favorable than the previous
agreements. The amended facilities are structured as two $1.5 billion credit
facilities, each with an option to issue up to $200 million as letters of
credit.
Debt
Covenants and Borrowing Limitations
Our
revolving credit agreements contain certain covenants and require us to maintain
our percentage of debt to total capitalization at a level that does not exceed
67.5%. The method for calculating our outstanding debt and other capital is
contractually defined. At December 31, 2006, this contractually-defined
percentage was 54.0%. Nonperformance of these covenants could result in an
event
of default under these credit agreements. At December 31, 2006, we complied
with
all of the covenants contained in these credit agreements. In addition, the
acceleration of our payment obligations, or the obligations of certain of our
subsidiaries, prior to maturity under any other agreement or instrument relating
to debt outstanding in excess of $50 million would cause an event of default
under these credit agreements and permit the lenders to declare the outstanding
amounts payable.
The
two
revolving credit facilities do not contain a material adverse change clause
in
the event of a draw on either facility.
Under
a
regulatory order, our utility subsidiaries, other than TCC, cannot incur
additional indebtedness if the issuer’s common equity would constitute less than
30% of its capital. In addition, this order restricts those utility subsidiaries
from issuing long-term debt unless that debt will be rated investment grade
by
at least one nationally recognized statistical rating organization. At December
31, 2006, all applicable utility subsidiaries complied with this
order.
Utility
Money Pool borrowings and external borrowings may not exceed amounts authorized
by regulatory orders. At December 31, 2006, we had not exceeded those authorized
limits.
Dividend
Policy and Restrictions
We
have
declared common stock dividends payable in cash in each quarter since July
1910,
representing 387 consecutive quarters. The Board of Directors increased the
quarterly dividend from $0.37 to $0.39 per share in October 2006. Future
dividends may vary depending upon our profit levels, operating cash flow levels
and capital requirements, as well as financial and other business conditions
existing at the time.
Credit
Ratings
Our
current credit ratings are as follows:
If
we or
any of our rated subsidiaries receive an upgrade from any of the rating agencies
listed above, our borrowing costs could decrease. If we receive a downgrade
in
our credit ratings by one of the rating agencies listed above, our borrowing
costs could increase and access to borrowed funds could be negatively
affected.
Cash
Flow
Managing
our cash flows is a major factor in maintaining our liquidity
strength.
Cash
from
operations, combined with a bank-sponsored receivables purchase agreement and
short-term borrowings, provides working capital and allows us to meet other
short-term cash needs. We use our corporate borrowing program to meet the
short-term borrowing needs of our subsidiaries. The
corporate borrowing program includes a Utility Money Pool, which funds the
utility subsidiaries, and a Nonutility Money Pool, which funds the majority
of
the nonutility subsidiaries. In addition, we also fund, as direct borrowers,
the
short-term debt requirements of other subsidiaries that are not participants
in
either money pool for regulatory or operational reasons. As of December 31,
2006, we had credit facilities totaling $3 billion to support our commercial
paper program.
The
maximum amount of commercial paper outstanding during 2006 was $325 million.
The
weighted-average interest rate of our commercial paper during 2006 was 4.96%.
We
generally use short-term borrowings to fund working capital needs, property
acquisitions and construction until long-term funding is arranged. Sources
of
long-term funding include issuance of common stock or long-term debt and
sale-leaseback or leasing agreements. Utility Money Pool borrowings and external
borrowings may not exceed authorized limits under regulatory orders. See the
discussion below for further detail related to the components of our cash
flows.
Operating
Activities
Net
Cash
Flows From Operating Activities increased in 2006 because we did not make a
pension contribution in 2006 compared with a $626 million contribution in 2005
and increased recovery of deferred fuel. In 2005, we initiated fuel proceedings
in Oklahoma, Texas, Virginia and Arkansas seeking recovery of increased fuel
costs.
Net
Cash
Flows From Operating Activities were approximately $2.7 billion in 2006
consisting primarily of Income
Before Discontinued Operations
of $992 million. Income Before
Discontinued
Operations included noncash expense items primarily for depreciation,
amortization, accretion, deferred taxes and deferred investment tax credits.
Under-recovered fuel costs decreased due to recoveries under proceedings we
initiated in Oklahoma, Texas, Virginia and Arkansas during 2005. Other changes
in assets and liabilities represent items that had a current period cash flow
impact, such as changes in working capital, as well as items that represent
future rights or obligations to receive or pay cash, such as regulatory assets
and liabilities. The current period activity in these asset and liability
accounts relates to a number of items; the most significant is a $232 million
decrease in cash related to customer deposits held for trading activities
generally due to lower gas and power market prices.
Net
Cash
Flows From Operating Activities were approximately $1.9 billion in 2005. We
produced Income Before
Discontinued
Operations of $787 million. Income Before
Discontinued
Operations included noncash expense items primarily for depreciation,
amortization, accretion, deferred taxes and deferred investment tax credits.
We
made contributions of $626 million to our pension trusts. Under-recovered fuel
costs increased due to the higher cost of fuel, especially natural gas. In
2005,
we initiated fuel proceedings in Oklahoma, Texas, Virginia and Arkansas seeking
recovery of our increased fuel costs. Other changes in assets and liabilities
represent items that had a current period cash flow impact, such as changes
in
working capital, as well as items that represent future rights or obligations
to
receive or pay cash, such as regulatory assets and liabilities. The current
period activity in these asset and liability accounts relates to a number of
items; the most significant are a $140 million cash increase from Accounts
Payable due to higher fuel and allowance acquisition costs not paid at December
31, 2005 and
an
increase
in Customer Deposits held for trading activities of $157 million related to
market prices.
Net
Cash
Flows From Operating Activities were $2.7 billion in 2004 consisting of our
Income Before Discontinued Operations of $1 billion and noncash charges of
$1.6
billion for depreciation, amortization and deferred taxes. We recorded $302
million in noncash income for carrying costs on Texas stranded cost recovery
and
recognized an after-tax, noncash Extraordinary Loss of $121 million to provide
for probable disallowances to TCC’s stranded generation costs. We realized gains
of $157
million
on sales
of assets, primarily the IPPs and our South Coast equity investment. We made
$231 million of contributions to our pension trusts. Changes
in Assets and Liabilities represent those items that had a current period cash
flow impact, such as changes in working capital, as well as items that represent
future rights or obligations to receive or pay cash, such as regulatory assets
and liabilities.
Changes
in working capital items resulted in cash from operations of $430 million
predominantly due to increased accrued income taxes. During
2004, we did not make any federal income tax payments for our 2004 federal
income tax liability since our consolidated tax group was not required to make
any 2004 quarterly estimated federal income tax payments.
Investing
Activities
| |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||