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American Electric Power Company 10-Q 2008 Documents found in this filing:UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
FORM
10-Q
[X]
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE
SECURITIES EXCHANGE ACT OF 1934
For The
Quarterly Period EndedSeptember 30,
2008
OR
[ ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE
SECURITIES EXCHANGE ACT OF 1934
For The
Transition Period from ____ to ____
Columbus
Southern Power Company and Indiana Michigan Power Company meet the conditions
set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore
filing this Form 10-Q with the reduced disclosure format specified in General
Instruction H(2) to Form 10-Q.
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX
TO QUARTERLY REPORTS ON FORM 10-Q
September
30, 2008
When
the following terms and abbreviations appear in the text of this report, they
have the meanings indicated below.
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:
AMERICAN
ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT’S FINANCIAL
DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
EXECUTIVE
OVERVIEW
Base
Rate Filings
Our
significant base rate filings include:
Ohio
Electric Security Plan Filings
In April
2008, the Ohio legislature passed Senate Bill 221, which amends the
restructuring law effective July 31, 2008 and requires electric utilities to
adjust their rates by filing an Electric Security Plan (ESP). In July
2008, within the parameters of the ESPs, CSPCo and OPCo each requested an annual
rate increase for 2009 through 2011 that would not exceed approximately 15% per
year.
Credit
Markets
In recent
months, the world and U.S. economies have experienced significant
slowdowns. These economic slowdowns have impacted and will continue
to impact our residential, commercial and industrial sales. Concurrently, the
financial markets have become increasingly unstable and constrained at both a
global and domestic level. This systemic marketplace distress is
impacting our access to capital, our liquidity, asset valuations in our trust
funds, the creditworthy status of our customers, suppliers and trading partners
and our cost of capital. Our financial staff actively manages these
factors with oversight from our risk committee. The uncertainties in
the credit markets could have significant implications on our subsidiaries since
they rely on continuing access to capital to fund operations and capital
expenditures.
The
current credit markets are constraining our ability to issue new debt, including
commercial paper, and refinance existing debt. Approximately $120
million and $300 million of our $16 billion of long-term debt as of September
30, 2008 will mature in the remainder of 2008 and 2009,
respectively. We intend to refinance these maturities. To
support our operations, we have $3.9 billion in aggregate credit facility
commitments. These commitments include 27 different banks with no
bank having more than 10% of our total bank commitments. In September
2008 and October 2008, we borrowed $600 million and $1.4 billion, respectively,
under our credit agreements to enhance our cash position during this period of
market disruptions. In October 2008, we also renewed our $600 million
sale of receivables agreement through October 2009. At September 30,
2008, our available liquidity was approximately $3 billion.
We cannot
predict the length of time the current credit situation will continue or the
impact on our future operations and our ability to issue debt at reasonable
interest rates. However, when market conditions improve, we plan to
repay the amounts drawn under the credit facilities, re-enter the commerical
paper market and issue other long-term debt. If there is not an
improvement in access to capital, we believe that we have adequate liquidity to
support our planned business operations and construction program
through 2009.
We have
significant investments in several trust funds to provide for future payments of
pensions, OPEB, nuclear decommissioning and spent nuclear fuel
disposal. All of our trust funds’ investments are well-diversified
and managed in compliance with all laws and regulations. The value of
the investments in these trusts has declined due to the decreases in the equity
and fixed income markets. Although the asset values are currently
lower, this has not affected the funds’ ability to make their required
payments. As of September 30, 2008, the decline in pension asset
values will not require us to make a contribution in 2008 or 2009.
We have
risk management contracts with numerous counterparties. Since open
risk management contracts are valued based on changes in market prices of the
related commodities, our exposures change daily. Our risk management
organization monitors these exposures on a daily basis to limit our economic and
financial statement impact on a counterparty basis. At September 30,
2008, our credit exposure net of collateral was approximately $827 million of
which approximately 84% is to investment grade counterparties. At
September 30, 2008, our exposure to financial institutions was $145
million, which represents 18% of our total credit exposure net of collateral
(all investment grade).
Capital
Expenditures
Due to
recent credit market instability, we are currently reviewing our projections for
capital expenditures from our previous projection of $6.75 billion for 2009
through 2010. We plan to identify reductions of approximately $750
million for 2009. We are evaluating possible additional
capital reductions for 2010. We are also reviewing our
projections for operation and maintenance expense. Our intent is to
keep operation and maintenance expense flat in 2009 as compared to
2008.
Cook
Plant Unit 1 Fire and Shutdown
Cook
Plant Unit 1 (Unit 1) is a 1,030 MW nuclear generating unit located in
Bridgman, Michigan. In September 2008, I&M shut down Unit 1 due
to turbine vibrations likely caused by blade failure which resulted in
a fire on the electric generator. This equipment is in the turbine
building and is separate and isolated from the nuclear reactor. The
steam turbines that caused the vibration were installed in 2006 and are under
warranty from the vendor. The warranty provides for the replacement
of the turbines if the damage was caused by a defect in the design or assembly
of the turbines. I&M is also working with its insurance company,
Nuclear Electric Insurance Limited (NEIL), and turbine vendor to evaluate
the extent of the damage resulting from the incident and the costs to return the
unit to service. We cannot estimate the ultimate costs of the outage
at this time. Management believes that I&M should recover a
significant portion of these costs through the turbine vendor’s warranty,
insurance and the regulatory process. Our
preliminary analysis indicates that Unit 1 could resume operations as early as
late first quarter/early second quarter of 2009 or as late as the second half of
2009, depending upon whether the damaged components can be repaired or whether
they need to be replaced.
I&M
maintains property insurance through NEIL with a $1 million
deductible. I&M also maintains a separate accidental outage
policy with NEIL whereby, after a 12 week deductible period, I&M is
entitled to weekly payments of $3.5 million during the outage period for a
covered loss. If the ultimate costs of the incident are not covered
by warranty, insurance or through the regulatory process or if the unit is not
returned to service in a reasonable period of time, it could have an adverse
impact on net income, cash flows and financial condition.
Hurricanes
During
the third quarter of 2008, our CSPCo, OPCo, SWEPCo and TCC service territories
were significantly impacted by Hurricanes Dolly, Gustav and/or
Ike. Through September 30, 2008, we had incurred $54 million in total
incremental operation and maintenance costs related to the three
hurricanes. Since we believe that cost recovery related to the
hurricanes is probable for most of these costs in our CSPCo, OPCo, and TCC
service territories, we recorded $37 million in regulatory assets for these
hurricane costs as of September 30, 2008. We intend
to pursue the recovery of $11 million of incremental hurricane costs incurred in
our SWEPCo service territory.
New
Generation
In May
2006, we announced plans to build the Stall Unit, a new intermediate load, 500
MW, natural gas-fired generating unit at SWEPCo’s existing Arsenal Hill Plant
location in Shreveport, Louisiana. SWEPCo has received approvals from
the Louisiana Public Service Commission (LPSC) and the Public Utility Commission
of Texas (PUCT) to construct the Stall Unit and is currently waiting for
approval from the APSC. The Stall Unit is estimated to cost $378
million, excluding AFUDC, and is expected to be in-service in
mid-2010.
In August
2006, we announced plans to jointly build the Turk Plant, a new base load, 600
MW, pulverized coal, ultra-supercritical generating unit in
Arkansas. SWEPCo has received approvals from the APSC and the LPSC to
construct the Turk Plant. In August 2008, the PUCT issued an order
approving the Turk Plant subject to certain conditions, including the capping of
capital costs of the Turk Plant at the $1.5 billion projected construction
cost. SWEPCo is also working with the Arkansas Department of
Environmental Quality for the approval of an air permit and the U.S. Army Corps
of Engineers for the approval of a wetlands and stream impact permit. Once
SWEPCo receives the air permit, they will commence construction. The
Turk Plant is estimated to cost $1.5 billion, excluding AFUDC, with SWEPCo’s
portion estimated to cost $1.1 billion. If these permits are approved
on a timely basis, the plant is expected to be in-service in 2012.
Fuel
Costs
We
currently estimate 2008 coal prices to increase by approximately 28% due to
escalating domestic prices and increased needs, primarily in the
east. We had initially expected coal costs to increase by 13% in
2008. We continue to see increases in prices due to expiring
lower-priced coal and transportation contracts being replaced with higher-priced
contracts. We have price risk exposure in Ohio, representing
approximately 20% of our fuel costs, since we do not have an active fuel cost
recovery mechanism. However, under Ohio’s amended restructuring law,
we have requested the PUCO to reinstate a fuel cost recovery mechanism effective
January 1, 2009. Fuel cost adjustment rate clauses in our other
jurisdictions will help offset future negative impacts of fuel price increases
on our gross margins.
RESULTS
OF OPERATIONS
Segments
Our
principal operating business segments and their related business activities are
as follows:
Utility
Operations
AEP
River Operations
Generation
and Marketing
The table
below presents our consolidated Income Before Discontinued Operations and
Extraordinary Loss by segment for the three and nine months ended September 30,
2008 and 2007.
AEP
Consolidated
Third Quarter of 2008
Compared to Third Quarter of 2007
Income
Before Discontinued Operations and Extraordinary Loss in 2008 decreased $33
million compared to 2007 primarily due to a decrease in Utility Operations
segment earnings of $31 million. The decrease in Utility Operations
segment earnings primarily relates to an increase in fuel and consumables
expense in Ohio and a decrease in cooling degree days throughout our service
territories, partially offset by increases in retail margins due to rate
increases in Ohio, Virginia, West Virginia, Texas and Oklahoma.
Average
basic shares outstanding increased to 402 million in 2008 from 399 million in
2007 primarily due to the issuance of shares under our incentive compensation
and dividend reinvestment plans. Actual shares outstanding were 403
million as of September 30, 2008.
Nine Months Ended September
30, 2008 Compared to Nine Months Ended September 30, 2007
Income
Before Discontinued Operations and Extraordinary Loss in 2008 increased $292
million compared to 2007 primarily due to income of $163 million (net of tax)
from the cash settlement received in 2008 related to a power purchase-and-sale
agreement with TEM and an increase in Utility Operations segment earnings of
$151 million. The increase in Utility Operations segment earnings
primarily relates to rate increases implemented since the second quarter of 2007
in Ohio, Virginia, West Virginia, Texas and Oklahoma and higher off-system
sales, partially offset by higher interest and fuel expenses.
Average
basic shares outstanding increased to 402 million in 2008 from 398 million in
2007 primarily due to the issuance of shares under our incentive compensation
and dividend reinvestment plans. Actual shares outstanding were 403
million as of September 30, 2008.
Utility
Operations
Our
Utility Operations segment includes 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.
Utility
Operations Income Summary
For
the Three and Nine Months Ended September 30, 2008 and 2007
Summary
of Selected Sales Data
For
Utility Operations
For
the Three and Nine Months Ended September 30, 2008 and 2007
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 associated number of customers within each.
Summary
of Weather Data
Summary
of Heating and Cooling Degree Days for Utility Operations
For
the Three and Nine Months Ended September 30, 2008 and 2007
Third Quarter of 2008
Compared to Third Quarter of 2007
Reconciliation
of Third Quarter of 2007 to Third Quarter of 2008
Income
from Utility Operations Before Discontinued Operations and Extraordinary
Loss
(in
millions)
Income
from Utility Operations Before Discontinued Operations and Extraordinary Loss
decreased $31 million to $357 million in 2008. The key drivers of the
decrease were a $60 million decrease in Gross Margin offset by a $5 million
decrease in Operating Expenses and Other and a $24 million decrease in Income
Tax Expense.
The major
components of the net decrease in Gross Margin were as follows:
Utility
Operating Expenses and Other and Income Taxes changed between years as
follows:
Nine Months Ended September
30, 2008 Compared to Nine Months Ended September 30, 2007
Reconciliation
of Nine Months Ended September 30, 2007 to Nine Months Ended September 30,
2008
Income
from Utility Operations Before Discontinued Operations and Extraordinary
Loss
(in
millions)
Income
from Utility Operations Before Discontinued Operations and Extraordinary Loss
increased $151 million to $1,030 million in 2008. The key drivers of
the increase were a $201 million increase in Gross Margin and a $16 million
decrease in Operating Expenses and Other offset by a $66 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:
AEP River
Operations
Third Quarter of 2008
Compared to Third Quarter of 2007
Income
Before Discontinued Operations and Extraordinary Loss from our AEP River
Operations segment decreased to $11 million in 2008 from $18 million in 2007
primarily due to significant disruptions of ship arrivals and departures as the
result of an oil spill in the New Orleans Harbor. Ship arrivals were
further disrupted by the impacts of Hurricanes Gustav and Ike, which caused
severe flooding on the Mississippi and Illinois Rivers. The decrease
in income was also due to higher diesel fuel prices. Additionally,
decreases in import demand and grain export demand have resulted in lower
freight demand, partially offset by increased coal exports.
Nine Months Ended September
30, 2008 Compared to Nine Months Ended September 30, 2007
Income
Before Discontinued Operations and Extraordinary Loss from our AEP River
Operations segment decreased to $21 million in 2008 from $40 million in 2007
primarily due to significant flooding on various inland waterways throughout
2008 and rising diesel fuel prices. Additionally, decreases in import
demand and grain export demand have resulted in lower freight demand, largely
the result of a slowing U.S. economy and a weak U.S. dollar. The
impact of Hurricanes Gustav and Ike and the oil spill in the New Orleans Harbor,
all of which occurred during the third quarter of 2008, also contributed to the
unfavorable variance.
Generation and
Marketing
Third Quarter of 2008
Compared to Third Quarter of 2007
Income
Before Discontinued Operations and Extraordinary Loss from our Generation and
Marketing segment increased to $16 million in 2008 from $3 million in 2007
primarily due to higher gross margins from its marketing activities and higher
gross margins due to improved price realization, plant performance and hedging
activities from its share of the Oklaunion Power Station.
Nine Months Ended September
30, 2008 Compared to Nine Months Ended September 30, 2007
Income
Before Discontinued Operations and Extraordinary Loss from our Generation and
Marketing segment increased to $43 million in 2008 from $17 million in 2007
primarily due to higher gross margins from its marketing activities and higher
gross margins due to improved price realization, plant performance and hedging
activities from its share of the Oklaunion Power Station.
All
Other
Third Quarter of 2008
Compared to Third Quarter of 2007
Loss
Before Discontinued Operations and Extraordinary Loss from All Other increased
to $10 million in 2008 from $2 million in 2007. The increase in the
loss primarily relates to higher interest expenses due to the issuance of AEP
Junior Subordinated Debentures and lower interest income from
affiliates.
Nine Months Ended September
30, 2008 Compared to Nine Months Ended September 30, 2007
Income
Before Discontinued Operations and Extraordinary Loss from All Other increased
to $133 million in 2008 from a $1 million loss in 2007. In 2008, we
had after-tax income of $163 million from a litigation settlement of a power
purchase and sale agreement with TEM related to the Plaquemine Cogeneration
Facility which was sold in the fourth quarter of 2006. The settlement
was recorded as a pretax credit to Asset Impairments and Other Related Charges
of $255 million in the accompanying Condensed Consolidated Statements of
Income. In 2007, we had a $16 million pretax gain ($10 million, net
of tax) on the sale of a portion of our investment in Intercontinental Exchange,
Inc. (ICE).
AEP System Income
Taxes
Income
Tax Expense decreased $13 million in the third quarter of 2008 compared to the
third quarter of 2007 primarily due to a decrease in pretax income.
Income
Tax Expense increased $165 million in the nine-month period ended September 30,
2008 compared to the nine-month period ended September 30, 2007 primarily due to
an increase in pretax income.
FINANCIAL
CONDITION
We
measure our financial condition by the strength of our balance sheet and the
liquidity provided by our cash flows.
Debt and Equity
Capitalization
Our ratio
of debt to total capital increased from 60.7% to 61.2% in 2008 due to our
issuance of debt to fund construction and our strategy to deal with the credit
situation by drawing cash from our credit facilities.
Liquidity
Liquidity,
or access to cash, is an important factor in determining our financial
stability. We are committed to maintaining adequate
liquidity. 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 long-term debt, sale-leaseback or leasing agreements and common
stock.
Credit
Markets
In recent
months, the financial markets have become increasingly unstable and constrained
at both a global and domestic level. This systemic marketplace
distress is impacting our access to capital, our liquidity and our cost of
capital. The uncertainties in the credit markets could have
significant implications on our subsidiaries since they rely on continuing
access to capital to fund operations and capital expenditures. The
current credit markets are constraining our ability to issue new debt, including
commercial paper, and refinance existing debt.
We
believe that we have adequate liquidity under our credit
facilities. In September 2008, in response to the bankruptcy of
certain companies and tightening of credit markets, we borrowed $600 million
under our credit lines to assure that cash is available to meet our working
capital needs. In October 2008, we borrowed an additional $1.4
billion under our existing credit facilities. We took this proactive
step to enhance our cash position during this period of market
disruptions.
We cannot
predict the length of time the current credit situation will continue or the
impact on our future operations and our ability to issue debt at reasonable
interest rates. However, when market conditions improve, we plan to
repay the amounts drawn under the credit facilities and issue other long-term
debt. If there is not an improvement in access to capital, we believe
that we have adequate liquidity to support our planned business operations and
construction program through 2009.
In the
first quarter of 2008, due to the exposure that bond insurers like Ambac
Assurance Corporation and Financial Guaranty Insurance Co. had in connection
with developments in the subprime credit market, the credit ratings of those
insurers were downgraded or placed on negative outlook. These market
factors contributed to higher interest rates in successful auctions and
increasing occurrences of failed auctions for tax-exempt long-term debt sold at
auction rates, including auctions of our tax-exempt long-term
debt. Consequently, we chose to exit the auction-rate debt
market. Through September 30, 2008, we reduced our outstanding
auction rate securities by $1.2 billion. As of September 30, 2008, we
had $272 million outstanding of tax-exempt long-term debt sold at auction rates
(rates range between 4.353% and 13%) that reset every 35 days. Approximately
$218 million of this debt relates to a lease structure with JMG that we are
unable to refinance at this time. In order to refinance this debt, we
need the lessor’s consent. This debt is insured by the previously
AAA-rated bond insurers. The instruments under which the bonds are
issued allow us to convert to other short-term variable-rate structures,
term-put structures and fixed-rate structures. We plan to continue
the conversion and refunding process to other permitted modes, including
term-put structures, variable-rate and fixed-rate structures, as opportunities
arise. As of September 30, 2008, $367 million of the prior auction
rate debt was issued in a weekly variable rate mode supported by letters of
credit at variable rates ranging from 6.5% to 8.25%, $495 million was issued at
fixed rates ranging from 4.5% to 5.625% and trustees held, on our behalf,
approximately $330 million of our reacquired auction rate tax-exempt long-term
debt which we plan to reissue to the public as market conditions
permit.
Credit
Facilities
We manage
our liquidity by maintaining adequate external financing
commitments. At September 30, 2008, our available liquidity was
approximately $3 billion as illustrated in the table below:
The
revolving credit facilities for commercial paper backup were structured as two
$1.5 billion credit facilities which were reduced by Lehman Brothers Holdings
Inc.’s commitment amount of $46 million following its bankruptcy. In
March 2008, the credit facilities were amended so that $750 million may be
issued under each credit facility as letters of credit.
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 September 30, 2008, we had credit
facilities totaling $3 billion to support our commercial paper
program. The maximum amount of commercial paper outstanding during
the first nine months of 2008 was $1.2 billion. The weighted-average
interest rate of our commercial paper during the first nine months of 2008 was
3.25%.
In April
2008, we entered into a $650 million 3-year credit agreement and a $350 million
364-day credit agreement which were reduced by Lehman Brothers Holdings Inc.’s
commitment amount of $23 million and $12 million, respectively, following its
bankruptcy. Under the facilities, we may issue letters of
credit. As of September 30, 2008, $372 million of letters of credit
were issued under the 3-year credit agreement to support variable rate demand
notes.
Investments
in Auction-Rate Securities
Prior to
June 30, 2008, we sold all of our investment in auction-rate securities at
par.
Sale
of Receivables
In
October 2008, we renewed our sale of receivables agreement. The sale
of receivables agreement provides a commitment of $600 million from bank
conduits to purchase receivables. This agreement will expire in
October 2009.
Debt
Covenants and Borrowing Limitations
Our
revolving credit agreements, including the new agreements entered into in April
2008, 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 September 30, 2008, this
contractually-defined percentage was 57.3%. Nonperformance of these
covenants could result in an event of default under these credit
agreements. At September 30, 2008, 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
major 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.
Our
revolving credit facilities do not permit the lenders to refuse a draw on any
facility if a material adverse change occurs.
Utility
Money Pool borrowings and external borrowings may not exceed amounts authorized
by regulatory orders. At September 30, 2008, 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. The Board of Directors declared a quarterly dividend of $0.41
per share in October 2008. 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. We
have the option to defer interest payments on the $315 million of AEP Junior
Subordinated Debentures issued in March 2008 for one or more periods of up to 10
consecutive years per period. During any period in which we defer
interest payments, we may not declare or pay any dividends or distributions on,
or redeem, repurchase or acquire, our common stock. We believe that
these restrictions will not have a material effect on our net income, cash
flows, financial condition or limit any dividend payments in the foreseeable
future.
Credit
Ratings
In the
first quarter of 2008, Moody’s changed its outlook from stable to negative for
APCo, SWEPCo, OPCo and TCC and affirmed its stable outlook for AEP and our other
rated subsidiaries. Also in the first quarter, Fitch downgraded PSO
and SWEPCo from A- to BBB+ for senior unsecured debt. In May 2008,
Fitch revised APCo’s outlook from stable to negative. 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.
Operating
Activities
Net Cash
Flows from Operating Activities increased in 2008 primarily due to the TEM
settlement.
Net Cash
Flows from Operating Activities were $2.1 billion in 2008 consisting primarily
of Income Before Discontinued Operations of $1.2 billion and $1.1 billion of
noncash Depreciation and Amortization. Other represents 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. Significant changes
in other items include an increase in under-recovered fuel reflecting higher
coal and natural gas prices.
Net Cash
Flows from Operating Activities were $1.6 billion in 2007 consisting primarily
of Income Before Discontinued Operations of $856 million and $1.1 billion
of noncash Depreciation and Amortization. Other represents items that
had a prior 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. Significant changes in
other items resulted in lower cash from operations due to a number of items, the
most significant of which relates primarily to the Texas CTC refund of fuel
over-recovery.
Investing
Activities
Net Cash
Flows Used for Investing Activities were $3.1 billion in 2008 primarily due to
Construction Expenditures for our environmental, distribution and new generation
investment plan.
Net Cash
Flows Used for Investing Activities were $2.9 billion in 2007 primarily due to
Construction Expenditures for our environmental, distribution and new generation
investment plan. We paid $512 million to purchase gas-fired
generating units to acquire capacity at a cost below that of building a new,
comparable plant.
In our
normal course of business, we purchase and sell investment securities with cash
available for short-term investments including the cash drawn against our credit
facilities in 2008. We also purchase and sell investment securities within
our nuclear trusts.
We
forecast approximately $1.2 billion of construction expenditures for the
remainder of 2008. Estimated construction expenditures are subject to
periodic review and modification and may vary based on the ongoing effects of
regulatory constraints, environmental regulations, business opportunities,
market volatility, economic trends, weather, legal reviews and the ability to
access capital. These construction expenditures will be funded
through cash flows from operations and financing activities.
Financing
Activities
Net Cash
Flows from Financing Activities in 2008 were $1.2 billion primarily due to
the issuance of additional debt including $315 million of Junior Subordinated
Debentures and a net increase of $1.3 billion in outstanding Senior
Unsecured Notes partially offset, by the reacquisition of a net $370 million of
Pollution Control Bonds and $125 million of Securitization Bonds. In
September 2008, we borrowed $600 million under our credit
agreements. See Note 9 – Financing Activities for a complete
discussion of long-term debt issuances and retirements.
Net Cash
Flows from Financing Activities in 2007 were $1.2 billion primarily due to
issuing $1.9 billion of debt securities including $1 billion of new debt for
plant acquisitions and construction and increasing short-term commercial paper
borrowings.
Off-balance Sheet
Arrangements
Under a
limited set of circumstances, we enter into off-balance sheet arrangements to
accelerate cash collections, reduce operational expenses and spread risk of loss
to third parties. Our current guidelines restrict the use of
off-balance sheet financing entities or structures to traditional operating
lease arrangements and sales of customer accounts receivable that we enter in
the normal course of business. Our significant off-balance sheet
arrangements are as follows:
For
complete information on each of these off-balance sheet arrangements see the
“Off-balance Sheet Arrangements” section of “Management’s Financial Discussion
and Analysis of Results of Operations” in the 2007 Annual Report.
Summary Obligation
Information
A summary
of our contractual obligations is included in our 2007 Annual Report and has not
changed significantly from year-end other than the debt issuances and
retirements discussed in “Cash Flow” above and the drawdowns and standby letters
of credit discussed in “Liquidity” above.
SIGNIFICANT
FACTORS
We
continue to be involved in various matters described in the “Significant
Factors” section of “Management’s Financial Discussion and Analysis of Results
of Operations” in our 2007 Annual Report. The 2007 Annual Report
should be read in conjunction with this report in order to understand
significant factors which have not materially changed in status since the
issuance of our 2007 Annual Report, but may have a material impact on our future
net income, cash flows and financial condition.
Ohio Electric Security Plan
Filings
In April
2008, the Ohio legislature passed Senate Bill 221, which amends the
restructuring law effective July 31, 2008 and requires electric utilities to
adjust their rates by filing an Electric Security Plan
(ESP). Electric utilities may file an ESP with a fuel cost recovery
mechanism. Electric utilities also have an option to file a Market
Rate Offer (MRO) for generation pricing. An MRO, from the date of its
commencement, could transition CSPCo and OPCo to full market rates no sooner
than six years and no later than ten years after the PUCO approves an
MRO. The PUCO has the authority to approve or modify the utilities’
ESP request. The PUCO is required to approve an ESP if, in the
aggregate, the ESP is more favorable to ratepayers than the MRO. Both
alternatives involve a “substantially excessive earnings” test based on what
public companies, including other utilities with similar risk profiles, earn on
equity. Management has preliminarily concluded, pending the outcome
of the ESP proceeding, that CSPCo’s and OPCo’s generation/supply operations are
not subject to cost-based rate regulation accounting. However, if a
fuel cost recovery mechanism is implemented within the ESP, CSPCo’s and OPCo’s
fuel and purchased power operations would be subject to cost-based rate
regulation accounting. Management is unable to predict the financial
statement impact of the restructuring legislation until the PUCO acts on
specific proposals made by CSPCo and OPCo in their ESPs.
In July
2008, within the parameters of the ESPs, CSPCo and OPCo filed with the PUCO to
establish rates for 2009 through 2011. CSPCo and OPCo did not file an
optional MRO. CSPCo and OPCo each requested an annual rate increase
for 2009 through 2011 that would not exceed approximately 15% per
year. A significant portion of the requested increases results from
the implementation of a fuel cost recovery mechanism (which excludes off-system
sales) that primarily includes fuel costs, purchased power costs including
mandated renewable energy, consumables such as urea, other variable production
costs and gains and losses on sales of emission allowances. The
increases in customer bills related to the fuel-purchased power cost recovery
mechanism would be phased-in over the three year period from 2009 through
2011. If the ESP is approved as filed, effective with January 2009
billings, CSPCo and OPCo will defer any fuel cost under-recoveries and related
carrying costs for future recovery. The under-recoveries and related
carrying costs that exist at the end of 2011 will be recovered over seven years
from 2012 through 2018. In addition to the fuel cost recovery
mechanisms, the requested increases would also recover incremental carrying
costs associated with environmental costs, Provider of Last Resort (POLR)
charges to compensate for the risk of customers changing electric suppliers,
automatic increases for distribution reliability costs and for unexpected
non-fuel generation costs. The filings also include programs for
smart metering initiatives and economic development and mandated energy
efficiency and peak demand reduction programs. In September 2008, the
PUCO issued a finding and order tentatively adopting rules governing MRO and ESP
applications. CSPCo and OPCo filed their ESP applications based on
proposed rules and requested waivers for portions of the proposed
rules. The PUCO denied the waiver requests in September 2008 and
ordered CSPCo and OPCo to submit information consistent with the tentative
rules. In October 2008, CSPCo and OPCo submitted additional
information related to proforma financial statements and information concerning
CSPCo and OPCo’s fuel procurement process. In October 2008, CSPCo and
OPCo filed an application for rehearing with the PUCO to challenge certain
aspects of the proposed rules.
Within
the ESPs, CSPCo and OPCo would also recover existing regulatory assets of $46
million and $38 million, respectively, for customer choice implementation and
line extension carrying costs. In addition, CSPCo and OPCo would
recover related unrecorded equity carrying costs of $30 million and $21 million,
respectively. Such costs would be recovered over an 8-year period
beginning January 2011. Hearings are scheduled for November 2008 and
an order is expected in the fourth quarter of 2008. If an order is
not received prior to January 1, 2009, CSPCo and OPCo have requested retroactive
application of the new rates back to January 1, 2009 upon
approval. Failure of the PUCO to ultimately approve the recovery of
the regulatory assets would have an adverse effect on future net income and cash
flows.
Cook Plant Unit 1 Fire and
Shutdown
Cook
Plant Unit 1 (Unit 1) is a 1,030 MW nuclear generating unit located in
Bridgman, Michigan. In September 2008, I&M shut down Unit 1 due to turbine
vibrations likely caused by blade failure which resulted in a fire on the
electric generator. This equipment is in the turbine building and is
separate and isolated from the nuclear reactor. The steam turbines
that caused the vibration were installed in 2006 and are under warranty from the
vendor. The warranty provides for the replacement of the turbines if
the damage was caused by a defect in the design or assembly of the
turbines. I&M is also working with its insurance
company, Nuclear Electric Insurance Limited (NEIL), and turbine
vendor to evaluate the extent of the damage resulting from the incident and the
costs to return the unit to service. We cannot estimate the ultimate
costs of the outage at this time. Management believes that I&M should
recover a significant portion of these costs through the turbine vendor’s
warranty, insurance and the regulatory process. Our
preliminary analysis indicates that Unit 1 could resume operations as early as
late first quarter/early second quarter of 2009 or as late as the second half of
2009, depending upon whether the damaged components can be repaired or whether
they need to be replaced.
I&M
maintains property insurance through NEIL with a $1 million
deductible. I&M also maintains a separate accidental outage
policy with NEIL whereby, after a 12 week deductible period, I&M is entitled
to weekly payments of $3.5 million during the outage period for a covered
loss. If the ultimate costs of the incident are not covered by
warranty, insurance or through the regulatory process or if the unit is not
returned to service in a reasonable period of time, it could have an adverse
impact on net income, cash flows and financial condition.
TCC Texas Restructuring
Appeals
Pursuant
to PUCT orders, TCC securitized its net recoverable stranded generation costs of
$2.5 billion and is recovering the principal and interest on the securitization
bonds over a period ending in 2020. TCC has refunded its net other
true-up regulatory liabilities of $375 million during the period October 2006
through June 2008 via a CTC credit rate rider. Cash paid for these
CTC refunds for the nine months ended September 30, 2008 and 2007 was $75
million and $207 million, respectively. TCC appealed the PUCT
stranded costs true-up and related orders seeking relief in both state and
federal court on the grounds that certain aspects of the orders are contrary to
the Texas Restructuring Legislation, PUCT rulemakings and federal law and fail
to fully compensate TCC for its net stranded cost and other true-up
items. Municipal customers and other intervenors also appealed the
PUCT true-up orders seeking to further reduce TCC’s true-up
recoveries.
In March
2007, the Texas District Court judge hearing the appeals of the true-up order
affirmed the PUCT’s April 2006 final true-up order for TCC with two significant
exceptions. The judge determined that the PUCT erred by applying an
invalid rule to determine the carrying cost rate for the true-up of stranded
costs and remanded this matter to the PUCT for further
consideration. The district court judge also determined that the PUCT
improperly reduced TCC’s net stranded plant costs for commercial
unreasonableness.
TCC, the
PUCT and intervenors appealed the district court decision to the Texas Court of
Appeals. In May 2008, the Texas Court of Appeals affirmed the
district court decision in all but one major respect. It reversed the
district court’s unfavorable decision finding that the PUCT erred by applying an
invalid rule to determine the carrying cost rate. The favorable
commercial unreasonableness decision was not reversed. The Texas
Court of Appeals denied intervenors’ motion for rehearing. In May
2008, TCC, the PUCT and intervenors filed petitions for review with the Texas
Supreme Court.
Management
cannot predict the outcome of these court proceedings and PUCT remand
decisions. If TCC ultimately succeeds in its appeals, it could have a
material favorable effect on future net income, cash flows and financial
condition. If municipal customers and other intervenors succeed in
their appeals it could have a substantial adverse effect on future net income,
cash flows and financial condition.
New
Generation
In 2008,
AEP completed or is in various stages of construction of the following
generation facilities:
Turk
Plant
In
November 2007, the APSC granted approval to build the Turk
Plant. Certain landowners filed a notice of appeal to the Arkansas
State Court of Appeals. In March 2008, the LPSC approved the
application to construct the Turk Plant.
In August
2008, the PUCT issued an order approving the Turk Plant with the following four
conditions: (a) the capping of capital costs for the Turk Plant at the $1.5
billion projected construction cost, excluding AFUDC, (b) capping CO2 emission
costs at $28 per ton through the year 2030, (c) holding Texas ratepayers
financially harmless from any adverse impact related to the Turk Plant not being
fully subscribed to by other utilities or wholesale customers and (d) providing
the PUCT all updates, studies, reviews, reports and analyses as previously
required under the Louisiana and Arkansas orders. An intervenor filed
a motion for rehearing seeking reversal of the PUCT’s
decision. SWEPCo filed a motion for rehearing stating that the two
cost cap restrictions are unlawful. In September 2008, the motions
for rehearing were denied. In October 2008, SWEPCo appealed the
PUCT’s order regarding the two cost cap restrictions. If the cost cap
restrictions are upheld and construction or emissions costs exceed the
restrictions, it could have a material adverse impact on future net income and
cash flows. In October 2008, an intervenor filed an appeal contending
that the PUCT’s grant of a conditional Certificate of Public Convenience and
Necessity for the Turk Plant was not necessary to serve retail
customers.
SWEPCo is
also working with the Arkansas Department of Environmental Quality for the
approval of an air permit and the U.S. Army Corps of Engineers for
the approval of a wetlands
and stream impact permit. Once SWEPCo receives the air permit, they
will commence construction. A request to stop pre-construction
activities at the site was filed in federal court by the same Arkansas
landowners who appealed the APSC decision to the Arkansas State Court of
Appeals. In July 2008, the federal court denied the request and the
Arkansas landowners appealed the denial to the U.S. Court of
Appeals.
In
January 2008 and July 2008, SWEPCo filed applications for authority with the
APSC to construct transmission lines necessary for service from the Turk
Plant. Several landowners filed for intervention status and one
landowner also contended he should be permitted to re-litigate Turk Plant
issues, including the need for the generation. The APSC granted their
intervention but denied the request to re-litigate the Turk Plant
issues. The landowner filed an appeal to the Arkansas State Court of
Appeals in June 2008.
The
Arkansas Governor’s Commission on Global Warming is scheduled to issue its final
report to the Governor by November 1, 2008. The Commission was
established to set a global warming pollution reduction goal together with a
strategic plan for implementation in Arkansas. If legislation is
passed as a result of the findings in the Commission’s report, it could impact
SWEPCo’s proposal to build the Turk Plant.
If SWEPCo
does not receive appropriate authorizations and permits to build the Turk Plant,
SWEPCo could incur significant cancellation fees to terminate its commitments
and would be responsible to reimburse OMPA, AECC and ETEC for their share of
paid costs. If that occurred, SWEPCo would seek recovery of its
capitalized costs including any cancellation fees and joint owner
reimbursements. As of September 30, 2008, SWEPCo has capitalized
approximately $448 million of expenditures and has significant contractual
construction commitments for an additional $771 million. As of
September 30, 2008, if the plant had been cancelled, cancellation fees of $61
million would have been required in order to terminate these construction
commitments. If the Turk Plant does not receive all necessary
approvals on reasonable terms and SWEPCo cannot recover its capitalized costs,
including any cancellation fees, it would have an adverse effect on future net
income, cash flows and possibly financial condition.
IGCC
Plants
The
construction of the West Virginia and Ohio IGCC plants are pending necessary
permits and regulatory approvals. In May 2008, the Virginia SCC
denied APCo’s request to reconsider the Virginia SCC’s previous denial of APCo’s
request to recover initial costs associated with a proposed IGCC plant in West
Virginia. In July 2008, the WVPSC issued a notice seeking comments
from parties on how the WVPSC should proceed regarding its earlier approval of
the IGCC plant. In July 2008, the IRS allocated $134 million in
future tax credits to APCo for the planned IGCC plant contingent upon the
commencement of construction, qualifying expenses being incurred and
certification of the IGCC plant prior to July 2010. Through September
30, 2008, APCo deferred for future recovery preconstruction IGCC costs of $19
million. If the West Virginia IGCC plant is cancelled, APCo plans to
seek recovery of its prudently incurred deferred pre-construction
costs. If the plant is cancelled and if the deferred costs are not
recoverable, it would have an adverse effect on future net income and cash
flows.
In Ohio,
CSPCo and OPCo continue to pursue the ultimate construction of the IGCC
plant. In September 2008, the Ohio Consumers’ Counsel filed a motion
with the PUCO requesting all Phase 1 cost recoveries be refunded to Ohio
ratepayers with interest. CSPCo and OPCo filed a response with the
PUCO that argued the Ohio Consumers’ Counsel’s motion was without legal merit
and contrary to past precedent. If CSPCo and OPCo were required to
refund some or all of the $24 million collected for IGCC pre-construction costs
and those costs were not recoverable in another jurisdiction in connection with
the construction of an IGCC plant, it would have an adverse effect on future net
income and cash flows.
Litigation
In the
ordinary course of business, we, along with our subsidiaries, are involved in
employment, commercial, environmental and regulatory
litigation. Since it is difficult to predict the outcome of these
proceedings, we cannot state what the eventual outcome will be, or what the
timing of the amount of any loss, fine or penalty may be. Management
does, however, assess the probability of loss for such contingencies and accrues
a liability for cases that have a probable likelihood of loss and if the loss
amount can be estimated. For details on our regulatory proceedings
and pending litigation see Note 4 – Rate Matters, Note 6 – Commitments,
Guarantees and Contingencies and the “Litigation” section of “Management’s
Financial Discussion and Analysis of Results of Operations” in the 2007 Annual
Report. Additionally, see Note 3 – Rate Matters and Note 4 –
Commitments, Guarantees and Contingencies included herein. Adverse
results in these proceedings have the potential to materially affect our net
income.
Environmental
Litigation
New Source Review (NSR)
Litigation: The Federal EPA, a number of states and certain
special interest groups filed complaints alleging that APCo, CSPCo, I&M,
OPCo and other nonaffiliated utilities, including Cincinnati Gas & Electric
Company, Dayton Power and Light Company (DP&L) and Duke Energy Ohio, Inc.
(Duke), modified certain units at coal-fired generating plants in violation of
the NSR requirements of the CAA.
In 2007,
the AEP System settled their complaints under a consent decree. CSPCo
jointly-owns Beckjord and Stuart Stations with Duke and DP&L. A
jury trial in May 2008 returned a verdict of no liability at the jointly-owned
Beckjord unit. In October 2008, the court approved a settlement in
the citizen suit action filed by Sierra Club against the jointly-owned units at
Stuart Station. Under the settlement, the joint-owners of Stuart
Station agreed to certain emission targets related to NOx, SO2 and
PM. We also agreed to make energy efficiency and renewable energy
commitments that are conditioned on PUCO approval for recovery of
costs. The joint-owners also agreed to forfeit 5,500 SO2 allowances
and provide $300 thousand to a third party organization to establish a
solar water heater rebate program.
Environmental
Matters
We are
implementing a substantial capital investment program and incurring additional
operational costs to comply with new environmental control
requirements. The sources of these requirements include:
In
addition, we are engaged in litigation with respect to certain environmental
matters, have been notified of potential responsibility for the clean-up of
contaminated sites and incur costs for disposal of spent nuclear fuel and future
decommissioning of our nuclear units. We are also engaged in the
development of possible future requirements to reduce CO2 and other
greenhouse gas (GHG) emissions to address concerns about global climate
change. All of these matters are discussed in the “Environmental
Matters” section of “Management’s Financial Discussion and Analysis of Results
of Operations” in the 2007 Annual Report.
Clean
Air Act Requirements
As
discussed in the 2007 Annual Report under “Clean Air Act Requirements,” various
states and environmental organizations challenged the Clean Air Mercury Rule
(CAMR) in the D. C. Circuit Court of Appeals. The court ruled that
the Federal EPA’s action delisting fossil fuel-fired power plants did not
conform to the procedures specified in the CAA. The court vacated and
remanded the model federal rules for both new and existing coal-fired power
plants to the Federal EPA. The Federal EPA filed a petition for
review by the U.S. Supreme Court. We are unable to predict the
outcome of this appeal or how the Federal EPA will respond to the
remand. In addition, in 2005, the Federal EPA issued a final rule,
the Clean Air Interstate Rule (CAIR), that requires further reductions in
SO2
and NOx emissions
and assists states developing new state implementation plans to meet 1997
national ambient air quality standards (NAAQS). CAIR reduces regional
emissions of SO2 and
NOx
(which can be transformed into PM and ozone) from power plants in the Eastern
U.S. (29 states and the District of Columbia). CAIR requires power
plants within these states to reduce emissions of SO2 by 50% by
2010, and by 65% by 2015. NOx emissions
will be subject to additional limits beginning in 2009, and will be reduced by a
total of 70% from current levels by 2015. Reduction of both SO2 and
NOx
would be achieved through a cap-and-trade program. In July 2008, the
D.C. Circuit Court of Appeals vacated the CAIR and remanded the rule to the
Federal EPA. The Federal EPA and other parties petitioned for
rehearing. We are unable to predict the outcome of the rehearing
petitions or how the Federal EPA will respond to the remand which could be
stayed or appealed to the U.S. Supreme Court. The Federal EPA also
issued revised NAAQS for both ozone and PM 2.5 that are
more stringent than the 1997 standards used to establish CAIR, which could
increase the levels of SO2 and
NOx
reductions required from our facilities.
In
anticipation of compliance with CAIR in 2009, I&M purchased $9 million of
annual CAIR NOx allowances
which are included in Deferred Charges and Other on our Condensed Consolidated
Balance Sheet as of September 30, 2008. The market value of annual
CAIR NOx allowances
decreased following this court decision. However, our
weighted-average cost of these allowances is below market. If CAIR
remains vacated, management intends to seek partial recovery of the cost of
purchased allowances. Any unrecovered portion would have an adverse
effect on future net income and cash flows. None of AEP’s other
subsidiaries purchased any significant number of CAIR
allowances. SO2 and
seasonal NOx allowances
allocated to our facilities under the Acid Rain Program and the NOx state
implementation plan (SIP) Call will still be required to comply with existing
CAA programs that were not affected by the court’s decision.
It is too
early to determine the full implication of these decisions on our environmental
compliance strategy. However, independent obligations under the CAA,
including obligations under future state implementation plan submittals, and
actions taken pursuant to our settlement of the NSR enforcement action, are
consistent with the actions included in our least-cost CAIR compliance
plan. Consequently, we do not anticipate making any immediate
changes in our near-term compliance plans as a result of these court
decisions.
Global
Climate Change
In July
2008, the Federal EPA issued an advance notice of proposed rulemaking (ANPR)
that requests comments on a wide variety of issues the agency is considering in
formulating its response to the U.S. Supreme Court’s decision in Massachusetts v.
EPA. In that case, the court determined that CO2 is an “air
pollutant” and that the Federal EPA has authority to regulate mobile sources of
CO2
emissions under the CAA if appropriate findings are made. The Federal
EPA has identified a number of issues that could affect stationary sources, such
as electric generating plants, if the necessary findings are made for mobile
sources, including the potential regulation of CO2 emissions
for both new and existing stationary sources under the NSR programs of the
CAA. We plan to submit comments and participate in any subsequent
regulatory development processes, but are unable to predict the outcome of the
Federal EPA’s administrative process or its impact on our
business. Also, additional legislative measures to address CO2 and other
GHGs have been introduced in Congress, and such legislative actions could impact
future decisions by the Federal EPA on CO2
regulation.
In
addition, the Federal EPA issued a proposed rule for the underground injection
and storage of CO2 captured
from industrial processes, including electric generating facilities, under the
Safe Drinking Water Act’s Underground Injection Control (UIC)
program. The proposed rules provide a comprehensive set of well
siting, design, construction, operation, closure and post-closure care
requirements. We plan to submit comments and participate in any
subsequent regulatory development process, but are unable to predict the outcome
of the Federal EPA’s administrative process or its impact on our
business. Permitting for our demonstration project at the Mountaineer
Plant will proceed under the existing UIC rules.
Clean
Water Act Regulations
In 2004,
the Federal EPA issued a final rule requiring all large existing power plants
with once-through cooling water systems to meet certain standards to reduce
mortality of aquatic organisms pinned against the plant’s cooling water intake
screen or entrained in the cooling water. The standards vary based on
the water bodies from which the plants draw their cooling water. We
expected additional capital and operating expenses, which the Federal EPA
estimated could be $193 million for our plants. We undertook
site-specific studies and have been evaluating site-specific compliance or
mitigation measures that could significantly change these cost
estimates.
In
January 2007, the Second Circuit Court of Appeals issued a decision remanding
significant portions of the rule to the Federal EPA. In July 2007,
the Federal EPA suspended the 2004 rule, except for the requirement that
permitting agencies develop best professional judgment (BPJ) controls for
existing facility cooling water intake structures that reflect the best
technology available for minimizing adverse environmental impact. The
result is that the BPJ control standard for cooling water intake structures in
effect prior to the 2004 rule is the applicable standard for permitting agencies
pending finalization of revised rules by the Federal EPA. We cannot
predict further action of the Federal EPA or what effect it may have on similar
requirements adopted by the states. We sought further review and
filed for relief from the schedules included in our permits.
In April
2008, the U.S. Supreme Court agreed to review decisions from the Second Circuit
Court of Appeals that limit the Federal EPA’s ability to weigh the retrofitting
costs against environmental benefits. Management is unable to predict
the outcome of this appeal.
Critical Accounting
Estimates
See the
“Critical Accounting Estimates” section of “Management’s Financial Discussion
and Analysis of Results of Operations” in the 2007 Annual Report for a
discussion of the estimates and judgments required for regulatory accounting,
revenue recognition, the valuation of long-lived assets, the accounting for
pension and other postretirement benefits and the impact of new accounting
pronouncements.
Adoption of New Accounting
Pronouncements
In
September 2006, the FASB issued SFAS 157 “Fair Value Measurements” (SFAS 157),
enhancing existing guidance for fair value measurement of assets and liabilities
and instruments measured at fair value that are classified in shareholders’
equity. The statement defines fair value, establishes a fair value
measurement framework and expands fair value disclosures. It
emphasizes that fair value is market-based with the highest measurement
hierarchy level being market prices in active markets. The standard
requires fair value measurements be disclosed by hierarchy level, an entity
includes its own credit standing in the measurement of its liabilities and
modifies the transaction price presumption. The standard also
nullifies the consensus reached in EITF Issue No. 02-3 “Issues Involved in
Accounting for Derivative Contracts Held for Trading Purposes and Contracts
Involved in Energy Trading and Risk Management Activities” (EITF 02-3) that
prohibited the recognition of trading gains or losses at the inception of a
derivative contract, unless the fair value of such derivative is supported by
observable market data. In February 2008, the FASB issued FSP SFAS
157-1 “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other
Accounting Pronouncements That Address Fair Value Measurements for Purposes of
Lease Classification or Measurement under Statement 13” which amends SFAS 157 to
exclude SFAS 13 “Accounting for Leases” and other accounting pronouncements that
address fair value measurements for purposes of lease classification or
measurement under SFAS 13. In February 2008, the FASB issued FSP SFAS
157-2 “Effective Date of FASB Statement No. 157” which delays the effective date
of SFAS 157 to fiscal years beginning after November 15, 2008 for all
nonfinancial assets and nonfinancial liabilities, except those that are
recognized or disclosed at fair value in the financial statements on a recurring
basis (at least annually). In October 2008, the FASB issued FSP SFAS
157-3 “Determining the Fair Value of a Financial Asset When the Market for That
Asset is Not Active” which clarifies application of SFAS 157 in markets that are
not active and provides an illustrative example. The provisions of
SFAS 157 are applied prospectively, except for a) changes in fair value
measurements of existing derivative financial instruments measured initially
using the transaction price under EITF 02-3, b) existing hybrid financial
instruments measured initially at fair value using the transaction price and c)
blockage discount factors. Although the statement is applied
prospectively upon adoption, in accordance with the provisions of SFAS 157
related to EITF 02-3, we recorded an immaterial transition adjustment to
beginning retained earnings. The impact of considering our own credit
risk when measuring the fair value of liabilities, including derivatives, had an
immaterial impact on fair value measurements upon adoption. We
partially adopted SFAS 157 effective January 1, 2008. FSP SFAS 157-3
is effective upon issuance. We will fully adopt SFAS 157 effective
January 1, 2009 for items within the scope of FSP SFAS 157-2. We
expect that the adoption of FSP SFAS 157-2 will have an immaterial impact on our
financial statements. See “SFAS 157 “Fair Value Measurements” (SFAS 157)”
section of Note 2.
In
February 2007, the FASB issued SFAS 159 “The Fair Value Option for Financial
Assets and Financial Liabilities” (SFAS 159), permitting entities to choose to
measure many financial instruments and certain other items at fair
value. The standard also establishes presentation and disclosure
requirements designed to facilitate comparison between entities that choose
different measurement attributes for similar types of assets and
liabilities. If the fair value option is elected, the effect of the
first remeasurement to fair value is reported as a cumulative effect adjustment
to the opening balance of retained earnings. The statement is applied
prospectively upon adoption. We adopted SFAS 159 effective January 1,
2008. At adoption, we did not elect the fair value option for any
assets or liabilities.
In March
2007, the FASB ratified EITF Issue No. 06-10 “Accounting for Collateral
Assignment Split-Dollar Life Insurance Arrangements” (EITF 06-10), a consensus
on collateral assignment split-dollar life insurance arrangements in which an
employee owns and controls the insurance policy. Under EITF 06-10, an
employer should recognize a liability for the postretirement benefit related to
a collateral assignment split-dollar life insurance arrangement in accordance
with SFAS 106 “Employers' Accounting for Postretirement Benefits Other Than
Pension” or Accounting Principles Board Opinion No. 12 “Omnibus Opinion – 1967”
if the employer has agreed to maintain a life insurance policy during the
employee's retirement or to provide the employee with a death benefit based on a
substantive arrangement with the employee. In addition, an employer
should recognize and measure an asset based on the nature and substance of the
collateral assignment split-dollar life insurance arrangement. EITF
06-10 requires recognition of the effects of its application as either (a) a
change in accounting principle through a cumulative effect adjustment to
retained earnings or other components of equity or net assets in the statement
of financial position at the beginning of the year of adoption or (b) a change
in accounting principle through retrospective application to all prior
periods. We adopted EITF 06-10 effective January 1, 2008 with a
cumulative effect reduction of $16 million ($10 million, net of tax) to
beginning retained earnings.
In June
2007, the FASB ratified the EITF Issue No. 06-11 “Accounting for Income Tax
Benefits of Dividends on Share-Based Payment Awards” (EITF 06-11), consensus on
the treatment of income tax benefits of dividends on employee share-based
compensation. The issue is how a company should recognize the income
tax benefit received on dividends that are paid to employees holding
equity-classified nonvested shares, equity-classified nonvested share units or
equity-classified outstanding share options and charged to retained earnings
under SFAS 123R, “Share-Based Payments.” Under EITF 06-11, a realized
income tax benefit from dividends or dividend equivalents that are charged to
retained earnings and are paid to employees for equity-classified nonvested
equity shares, nonvested equity share units and outstanding equity share options
should be recognized as an increase to additional paid-in capital. We adopted
EITF 06-11 effective January 1, 2008. EITF 06-11 is applied
prospectively to the income tax benefits of dividends on equity-classified
employee share-based payment awards that are declared in fiscal years after
December 15, 2007. The adoption of this standard had an immaterial
impact on our financial statements.
In April
2007, the FASB issued FSP FIN 39-1 “Amendment of FASB Interpretation No. 39”
(FIN 39-1). It amends FASB Interpretation No. 39 “Offsetting of
Amounts Related to Certain Contracts” by replacing the interpretation’s
definition of contracts with the definition of derivative instruments per SFAS
133. It also requires entities that offset fair values of derivatives
with the same party under a netting agreement to net the fair values (or
approximate fair values) of related cash collateral. The entities
must disclose whether or not they offset fair values of derivatives and related
cash collateral and amounts recognized for cash collateral payables and
receivables at the end of each reporting period. We adopted FIN 39-1 effective
January 1, 2008. This standard changed our method of netting certain
balance sheet amounts and reduced assets and liabilities. It requires
retrospective application as a change in accounting
principle. Consequently, we reduced total assets and liabilities on
the December 31, 2007 balance sheet by $47 million each. See “FSP FIN
39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1)” section of Note
2.
QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Market
Risks
Our
Utility Operations segment is exposed to certain market risks as a major power
producer and marketer of wholesale electricity, coal and emission
allowances. These risks include commodity price risk, interest rate
risk and credit risk. In addition, we may be exposed to foreign
currency exchange risk because occasionally we procure various services and
materials used in our energy business from foreign suppliers. These
risks represent the risk of loss that may impact us due to changes in the
underlying market prices or rates.
Our
Generation and Marketing segment, operating primarily within ERCOT, transacts in
wholesale energy trading and marketing contracts. This segment is
exposed to certain market risks as a marketer of wholesale
electricity. These risks include commodity price risk, interest rate
risk and credit risk. These risks represent the risk of loss that may
impact us due to changes in the underlying market prices or rates.
All Other
includes natural gas operations which holds forward natural gas contracts that
were not sold with the natural gas pipeline and storage assets. These
contracts are financial derivatives, which will gradually liquidate and
completely expire in 2011. Our risk objective is to keep these
positions generally risk neutral through maturity.
We employ
risk management contracts including physical forward purchase and sale contracts
and financial forward purchase and sale contracts. We engage in risk
management of electricity, natural gas, coal and emissions and to a lesser
degree other commodities associated with our energy business. As a
result, we are subject to price risk. The amount of risk taken is
determined by the commercial operations group in accordance with the market risk
policy approved by the Finance Committee of our Board of
Directors. Our market risk oversight staff independently monitors our
risk policies, procedures and risk levels and provides members of the Commercial
Operations Risk Committee (CORC) various daily, weekly and/or monthly reports
regarding compliance with policies, limits and procedures. The CORC
consists of our President – AEP Utilities, Chief Financial Officer, Senior Vice
President of Commercial Operations and Chief Risk Officer. When
commercial activities exceed predetermined limits, we modify the positions to
reduce the risk to be within the limits unless specifically approved by the
CORC.
The
Committee of Chief Risk Officers (CCRO) adopted disclosure standards for risk
management contracts to improve clarity, understanding and consistency of
information reported. The following tables provide information on our
risk management activities.
Mark-to-Market Risk
Management Contract Net Assets (Liabilities)
The
following two tables summarize the various mark-to-market (MTM) positions
included on our Condensed Consolidated Balance Sheet as of September 30, 2008
and the reasons for changes in our total MTM value included on our Condensed
Consolidated Balance Sheet as compared to December 31, 2007.
Reconciliation
of MTM Risk Management Contracts to
Condensed
Consolidated Balance Sheet
September
30, 2008
(in
millions)
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