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 Ended September 30, 2008March 31, 2009
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from ____ to ____
Commission | | Registrant, State of Incorporation, | | I.R.S. Employer |
File Number | | Address of Principal Executive Offices, and Telephone Number | | Identification No. |
| | | | |
1-3525 | | AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation) | | 13-4922640 |
1-3457 | | APPALACHIAN POWER COMPANY (A Virginia Corporation) | | 54-0124790 |
1-2680 | | COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) | | 31-4154203 |
1-3570 | | INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) | | 35-0410455 |
1-6543 | | OHIO POWER COMPANY (An Ohio Corporation) | | 31-4271000 |
0-343 | | PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation) | | 73-0410895 |
1-3146 | | SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation) | | 72-0323455 |
| | | | |
All Registrants | | 1 Riverside Plaza, Columbus, Ohio 43215-2373 | | |
| | Telephone (614) 716-1000 | | |
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. |
Yes X | No |
Indicate by check mark whether American Electric Power Company, Inc. has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). |
Yes | No |
Indicate by check mark whether Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). |
Yes | No |
Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of ‘large accelerated filer,’ ‘accelerated filer’ and ‘smaller reporting company’ in Rule 12b-2 of the Exchange Act. |
Large accelerated filer X Accelerated filer Non-accelerated filer Smaller reporting company |
Indicate by check mark whether Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company are large accelerated filers, accelerated filers, non-accelerated filers or smaller reporting companies. See the definitions of ‘large accelerated filer,’ ‘accelerated filer’ and ‘smaller reporting company’ in Rule 12b-2 of the Exchange Act. |
Large accelerated filer Accelerated filer Non-accelerated filer X Smaller reporting company |
|
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act). |
Yes | No X |
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.
| | | Number of shares of common stock outstanding of the registrants at OctoberApril 30, 20082009
|
| | | |
American Electric Power Company, Inc. | 403,554,634 | | 476,760,862 |
| | | ($6.50 par value) |
Appalachian Power Company | | | 13,499,500 |
| | | (no par value) |
Columbus Southern Power Company | | | 16,410,426 |
| | | (no par value) |
Indiana Michigan Power Company | | | 1,400,000 |
| | | (no par value) |
Ohio Power Company | | | 27,952,473 |
| | | (no par value) |
Public Service Company of Oklahoma | | | 9,013,000 |
| | | ($15 par value) |
Southwestern Electric Power Company | | | 7,536,640 |
| | | ($18 par value) |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX TO QUARTERLY REPORTS ON FORM 10-Q
September 30, 2008March 31, 2009
|
Glossary of Terms | |
| |
Forward-Looking Information | |
| |
Part I. FINANCIAL INFORMATION | |
| | |
| Items 1, 2 and 3 - Financial Statements, Management’s Financial Discussion and Analysis and Quantitative and Qualitative Disclosures About Risk Management Activities: | |
American Electric Power Company, Inc. and Subsidiary Companies: | |
| Management’s Financial Discussion and Analysis of Results of Operations | |
| Quantitative and Qualitative Disclosures About Risk Management Activities | |
| Condensed Consolidated Financial Statements | |
| Index to Condensed Notes to Condensed Consolidated Financial Statements | |
| | |
Appalachian Power Company and Subsidiaries: | |
| Management’s Financial Discussion and Analysis | |
| Quantitative and Qualitative Disclosures About Risk Management Activities | |
| Condensed Consolidated Financial Statements | |
| Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries | |
| | |
Columbus Southern Power Company and Subsidiaries: | |
| Management’s Narrative Financial Discussion and Analysis | |
| Quantitative and Qualitative Disclosures About Risk Management Activities | |
| Condensed Consolidated Financial Statements | |
| Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries | |
| | |
Indiana Michigan Power Company and Subsidiaries: | |
| Management’s Narrative Financial Discussion and Analysis | |
| Quantitative and Qualitative Disclosures About Risk Management Activities | |
| Condensed Consolidated Financial Statements | |
| Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries | |
|
Ohio Power Company Consolidated: |
| Management’s Financial Discussion and Analysis |
| Quantitative and Qualitative Disclosures About Risk Management Activities |
Condensed Consolidated Financial Statements |
Index to Condensed Notes to Condensed Consolidated Financial Statements |
|
Appalachian Power Company and Subsidiaries: |
Management’s Financial Discussion and Analysis |
Quantitative and Qualitative Disclosures About Risk Management Activities |
Condensed Consolidated Financial Statements |
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries |
| |
Columbus Southern PowerPublic Service Company and Subsidiaries:of Oklahoma: |
| Management’s Narrative Financial Discussion and Analysis |
| Quantitative and Qualitative Disclosures About Risk Management Activities |
| Condensed Consolidated Financial Statements |
| Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries |
| |
Indiana MichiganSouthwestern Electric Power Company and Subsidiaries:Consolidated: |
| Management’s Narrative Financial Discussion and Analysis |
| Quantitative and Qualitative Disclosures About Risk Management Activities |
| Condensed Consolidated Financial Statements |
| Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries |
|
Ohio Power Company Consolidated: |
Management’s Financial Discussion and Analysis |
Quantitative and Qualitative Disclosures About Risk Management Activities |
Condensed Consolidated Financial Statements |
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries |
|
Public Service Company of Oklahoma: |
Management’s Financial Discussion and Analysis |
Quantitative and Qualitative Disclosures About Risk Management Activities |
Condensed Financial Statements |
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries |
|
Southwestern Electric Power Company Consolidated: |
Management’s Financial Discussion and Analysis |
Quantitative and Qualitative Disclosures About Risk Management Activities |
Condensed Consolidated Financial Statements |
Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries |
|
Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries | |
| | |
Combined Management’s Discussion and Analysis of Registrant Subsidiaries | |
| | |
Controls and Procedures | |
| | | |
Part II. OTHER INFORMATION | |
| |
| Item 1. | Legal Proceedings | |
| Item 1A. | Risk Factors | |
| Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | |
Item 4. | Submission of Matters to a Vote of Security Holders |
Item 5. | Other Information | |
| Item 6. | Exhibits: |
Exhibit 10(a) (AEP) |
| | | | | Exhibit 10(b) (AEP)12 | |
| | | | | Exhibit 10(c) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)31(a) | |
| | | | | Exhibit 10(d) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)31(b) | |
| | | | | Exhibit 10(e) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)32(a) | |
| | | | | Exhibit 10(f) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo)32(b) | |
Exhibit 12 (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo) |
Exhibit 31(a) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo) |
Exhibit 31(b) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo) |
Exhibit 32(a) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo) |
Exhibit 32(b) (AEP, APCo, CSPCo, I&M, OPCo, PSO, SWEPCo) |
| |
SIGNATURE | | |
This combined Form 10-Q is separately filed by American Electric Power Company, Inc., Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants. |
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
AEGCo | | AEP Generating Company, an AEP electric utility subsidiary. |
AEP or Parent | | American Electric Power Company, Inc. |
AEP Consolidated | | AEP and its majority owned consolidated subsidiaries and consolidated affiliates. |
AEP Credit | | AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility revenues for affiliated electric utility companies. |
AEP East companies | | APCo, CSPCo, I&M, KPCo and OPCo. |
AEPSC | | American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries. |
AEP System or the System | | American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries. |
AEP Power Pool | | Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation and resultant wholesale off-system sales of the member companies. |
AEPSC | | American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries. |
AEP System | | American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries. |
AEP West companies | | PSO, SWEPCo, TCC and TNC. |
AFUDC | | Allowance for Funds Used During Construction. |
ALJ | | Administrative Law Judge. |
AOCI | | Accumulated Other Comprehensive Income. |
APB | | Accounting Principles Board Opinion. |
APCo | | Appalachian Power Company, an AEP electric utility subsidiary. |
APSC | | Arkansas Public Service Commission. |
CAA | | Clean Air Act. |
CO2 | | Carbon Dioxide. |
Cook Plant | | Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M. |
CSPCo | | Columbus Southern Power Company, an AEP electric utility subsidiary. |
CSW | | Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.). |
CSW Operating Agreement | | Agreement, dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing generating capacity allocation. This agreement was amended in May 2006 to remove TCC and TNC. AEPSC acts as the agent. |
CTC | | Competition Transition Charge. |
CWIP | | Construction Work in Progress. |
DETM | | Duke Energy Trading and Marketing L.L.C., a risk management counterparty. |
DOE | | United States Department of Energy. |
E&R | | Environmental compliance and transmission and distribution system reliability. |
EaR | | Earnings at Risk, a method to quantify risk exposure. |
EIS | | Energy Insurance Services, Inc., a protected cell insurance company that AEP consolidates under FIN 46R. |
EITF | | Financial Accounting Standards Board’s Emerging Issues Task Force. |
EPSEITF 06-10 | | Earnings Per Share.EITF Issue No. 06-10 “Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements.” |
ENEC | | Expanded Net Energy Cost. |
ERCOT | | Electric Reliability Council of Texas. |
ETTERISA | | Employee Retirement Income Security Act of 1974, as amended. |
ESP | | Electric Transmission Texas, LLC, a 50% equity interest joint venture with MidAmerican Energy Holding Company formed to own and operate electric transmission facilities in ERCOT.Security Plan. |
FASB | | Financial Accounting Standards Board. |
Federal EPA | | United States Environmental Protection Agency. |
FERC | | Federal Energy Regulatory Commission. |
FIN | | FASB Interpretation No. |
FIN 46R | | FIN 46R, “Consolidation of Variable Interest Entities.” |
FIN 48 | | |
FIN 48, “Accounting for Uncertainty in Income Taxes” and FASB Staff Position FIN 48-1 “Definition of Settlement in FASB Interpretation No. 48.”
FTRFSP FIN 39-1 | | Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for
certain congestion-related transmission charges that arise when the power grid is congested
resulting in differences in locational prices. FSP FIN 39-1, “Amendment of FASB Interpretation No. 39.” |
GAAP | | Accounting Principles Generally Accepted in the United States of America. |
HPL | | Houston Pipeline Company, a former AEP subsidiary. |
IGCC | | Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas. |
Interconnection Agreement | | Agreement, dated July 6, 1951, as amended, by and among APCo, CSPCo, I&M, KPCo and OPCo, defining the sharing of costs and benefits associated with their respective generating plants. |
IRS | | Internal Revenue Service. |
IURC | | Indiana Utility Regulatory Commission. |
I&M | | Indiana Michigan Power Company, an AEP electric utility subsidiary. |
JBR | | Jet Bubbling Reactor. |
JMG | | JMG Funding LP. |
KGPCo | | Kingsport Power Company, an AEP electric utility subsidiary. |
KPCo | | Kentucky Power Company, an AEP electric utility subsidiary. |
KPSC | | Kentucky Public Service Commission. |
kV | | Kilovolt. |
KWH | | Kilowatthour. |
LPSC | | Louisiana Public Service Commission. |
MISO | | Midwest Independent Transmission System Operator. |
MLR | | Member load ratio, the method used to allocate AEP Power Pool transactions to its members. |
MMBtu | | Million British Thermal Units. |
MTM | | Mark-to-Market. |
MW | | Megawatt. |
MWH | | Megawatthour. |
NOx | | Nitrogen oxide. |
Nonutility Money Pool | | AEP System’sConsolidated’s Nonutility Money Pool. |
NSR | | New Source Review. |
OCC | | Corporation Commission of the State of Oklahoma. |
OPCo | | Ohio Power Company, an AEP electric utility subsidiary. |
OPEB | | Other Postretirement Benefit Plans. |
OTC | | Over-the-counter.Over the counter. |
PATH | | Potomac Appalachian Transmission Highline, LLC and its subsidiaries, a joint venture with Allegheny Energy Inc. formed to own and operate electric transmission facilities in PJM. |
PJM | | Pennsylvania – New Jersey – Maryland regional transmission organization. |
PM | | Particulate Matter. |
PSO | | Public Service Company of Oklahoma, an AEP electric utility subsidiary. |
PUCO | | Public Utilities Commission of Ohio. |
PUCT | | Public Utility Commission of Texas. |
Registrant Subsidiaries | | AEP subsidiaries which are SEC registrants; APCo, CSPCo, I&M, OPCo, PSO and SWEPCo. |
REP | | Texas Retail Electric Provider. |
Risk Management Contracts | | Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges. |
Rockport Plant | | A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana, owned by AEGCo and I&M. |
RSP | | Rate Stabilization Plan. |
RTO | | Regional Transmission Organization. |
S&P | | Standard and Poor’s. |
SCR | | Selective Catalytic Reduction. |
SEC | | United States Securities and Exchange Commission. |
SECA | | Seams Elimination Cost Allocation. |
SEET | | Significant Excess Earnings Test. |
SFAS | | Statement of Financial Accounting Standards issued by the Financial Accounting Standards Board. |
SFAS 71 | | Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation.” |
SFAS 133 | | Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.” |
SFAS 157 | | Statement of Financial Accounting Standards No. 157, “Fair Value Measurements.” |
SIA | | System Integration Agreement. |
SNF | | Spent Nuclear Fuel. |
SO2 | | Sulfur Dioxide. |
SPP | | Southwest Power Pool. |
Stall Unit | | J. Lamar Stall Unit at Arsenal Hill Plant. |
Sweeny | | Sweeny Cogeneration Limited Partnership, owner and operator of a four unit, 480 MW gas-fired generation facility, owned 50% by AEP. AEP’s 50% interest in Sweeny was sold in October 2007. |
SWEPCo | | Southwestern Electric Power Company, an AEP electric utility subsidiary. |
TCC | | AEP Texas Central Company, an AEP electric utility subsidiary. |
TCRR | | Transmission Cost Recovery Rider. |
TEM | | SUEZ Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing, Inc.). |
Texas Restructuring Legislation | | Legislation enacted in 1999 to restructure the electric utility industry in Texas. |
TNC | | AEP Texas North Company, an AEP electric utility subsidiary. |
True-up Proceeding | | A filing made under the Texas Restructuring Legislation to finalize the amount of stranded costs and other true-up items and the recovery of such amounts. |
Turk Plant | | John W. Turk, Jr. Plant. |
Utility Money Pool | | AEP System’s Utility Money Pool. |
VaR | | Value at Risk, a method to quantify risk exposure. |
Virginia SCC | | Virginia State Corporation Commission. |
WPCo | | Wheeling Power Company, an AEP electric distribution subsidiary. |
WVPSC | | Public Service Commission of West Virginia. |
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:
· | The economic climate and growth in, or contraction within, our service territory and changes in market demand and demographic patterns. |
· | Inflationary or deflationary interest rate trends. |
· | Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impairing our ability to finance new capital projects and refinance existing debt at attractive rates. |
· | The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between incurring costs and recovery is long and the costs are material. |
· | Electric load and customer growth. |
· | Weather conditions, including storms. |
· | Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters. |
· | Availability of generating capacity and the performance of our generating plants.plants including our ability to restore Indiana Michigan Power Company’s Donald C. Cook Nuclear Plant Unit 1 in a timely manner. |
· | Our ability to recover regulatory assets and stranded costs in connection with deregulation. |
· | Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates. |
· | Our ability to build or acquire generating capacity and transmission line facilities (including our ability to obtain any necessary regulatory approvals and permits) when needed at acceptable prices and terms and to recover those costs (including the costs of projects that are cancelled) through applicable rate cases or competitive rates. |
· | New legislation, litigation and government regulation including requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances. |
· | Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions (including rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance). |
· | Resolution of litigation (including disputes arising from the bankruptcy of Enron Corp. and related matters). |
· | Our ability to constrain operation and maintenance costs. |
· | The economic climate and growth or contraction, in our service territory and changes in market demand and demographic patterns. |
· | Inflationary and interest rate trends. |
· | Volatility in the financial markets, particularly developments affecting the availability of capital on reasonable terms and developments impacting our ability to refinance existing debt at attractive rates. |
· | Our ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities. |
· | Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading markets.market. |
· | Actions of rating agencies, including changes in the ratings of debt. |
· | Volatility and changes in markets for electricity, natural gas, coal, nuclear fuel and other energy-related commodities. |
· | Changes in utility regulation, including the implementation of the recently-passedrecently passed utility law in Ohio and the allocation of costs within RTOs.regional transmission organizations, including PJM and SPP. |
· | Accounting pronouncements periodically issued by accounting standard-setting bodies. |
· | The impact of volatility in the capital markets on the value of the investments held by our pension, other postretirement benefit plans and nuclear decommissioning trust and the impact on future funding requirements. |
· | Prices for power that we generate and sell at wholesale. |
· | Changes in technology, particularly with respect to new, developing or alternative sources of generation. |
· | Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events. |
The registrantsAEP and its Registrant Subsidiaries expressly disclaim any obligation to update any forward-looking information.
|
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
EXECUTIVE OVERVIEW
Base Rate FilingsEconomic Slowdown
Our significantThe financial struggles of the U.S. economy continue to impact our industrial sales as well as sales opportunities in the wholesale market. Industrial sales in various sections of our service territories are decreasing due to reduced shifts and suspended operations by some of our large industrial customers. Although many sections of our service territories are experiencing slowdowns in new construction, our residential and commercial customer base rate filings include:appears to be stable. As a result of these economic issues, we are currently monitoring the following:
Operating Company | | Jurisdiction | | Revised Annual Rate Increase Request | | Projected Effective Date of Rate Increase | |
| | | | (in millions) | | | |
APCo | | Virginia | | $ | 208 | | October 2008 (a) | |
PSO | | Oklahoma | | | 117 | (b) | February 2009 | |
I&M | | Indiana | | | 80 | | June 2009 | |
(a)· | SubjectMargins from Off-system Sales - Margins from off-system sales continue to refund. An October settlement agreement of $168 million is pending withdecrease due to reductions in sales volumes and weak market power prices, reflecting reduced overall demand for electricity. We currently forecast that off-system sales volumes will decrease by approximately 30% in 2009. These trends will most likely continue until the Virginia SCC.economy rebounds and electricity demand and prices increase.
|
(b) | Net |
· | Industrial KWH Sales - Industrial KWH sales for the quarter ended March 31, 2009 were down 15% in comparison to the quarter ended March 31, 2008. Approximately half of estimated amountsthis decrease was due to cutbacks or closures by six of our large metals customers. We also experienced additional significant decreases in KWH sales to customers in the plastics, rubber, auto and paper manufacturing industries. Since our trends for industrial sales are usually similar to the nation’s industrial production, these trends are likely to continue until industrial production improves. |
| |
· | Risk of Loss of Major Customers - We monitor the financial strength and viability of each of our major industrial customers individually. We have factored this analysis into our operational planning. Our largest customer, Ormet, an industrial customer with a 520 MW load, recently announced that PSO expectsit is in dispute with its sole customer which could potentially force Ormet to recover through a generation cost recovery rider which will terminate upon implementation of the new base rates.halt production. |
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.
CreditCapital 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, theThe financial markets have become increasingly unstable and constrainedremain volatile at both a global and domestic level. This systemic marketplace distress is impactingcould impact 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 staffWe actively managesmanage 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 market situation will continue or theits impact on our future operations and our ability to issue debt at reasonable interest rates. However, when market conditions improve,Despite the current volatile markets, we planwere able to repayissue approximately $1 billion of long-term debt in the amounts drawn under the credit facilities, re-enter the commerical paper marketfirst quarter of 2009 and issue other long-term debt. If there is not an improvement$1.64 billion (net proceeds) of AEP common stock in access to capital, weApril 2009.
We believe that we have adequate liquidity to support our planned business operations and construction program through 2009.for the remainder of 2009 due to the following:
· | As of March 31, 2009, we had $2.2 billion in aggregate available liquidity under our credit facilities. These credit facilities include 27 different banks with no one bank having more than 10% of our total bank commitments. In April 2009, we allowed $350 million of our credit facility commitments to expire. As of March 31, 2009, cash and cash equivalents were $710 million. |
· | Of our $17 billion of long-term debt as of March 31, 2009, approximately $300 million will mature during the remainder of 2009 (approximately 1.8% of our outstanding long-term debt as of March 31, 2009). The $300 million of remaining 2009 maturities exclude payments due for securitization bonds which we recover directly from ratepayers. |
· | In April 2009, we issued 69 million shares of common stock at $24.50 per share for net proceeds of $1.64 billion. We used $1.25 billion of the proceeds to repay part of the cash drawn under our credit facilities. These transactions improved our debt to capital ratio to 58.1% assuming no other changes from our March 31, 2009 balance sheet. With the remaining proceeds, we intend to pay down other existing debt. These actions will help to support our investment grade ratings and maintain financial flexibility. |
· | We believe that our projected cash flows from operating activities are sufficient to support our ongoing operations. |
Approximately $1.7 billion of outstanding long-term debt will mature in 2010, excluding payments due for securitization bonds which we recover directly from ratepayers. We intend to refinance or repay our debt maturities.
We havesponsor several trust funds with significant investments in several trust fundsintended to provide for future payments of pensions, OPEB, nuclear decommissioning and spent nuclear fuel disposal. AllAlthough all of our trust funds’ investments are well-diversifieddiversified and managed in compliance with all laws and regulations. Theregulations, the value of the investments in these trusts has declined substantially over the past year due to the decreases in thedomestic and international 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, theThe decline in pension asset values will not require us to make a contribution under ERISA in 2008 or 2009. We estimate that we will need to make minimum contributions to our pension trust of $475 million in 2010 and $283 million in 2011. However, estimates may vary significantly based on market returns, changes in actuarial assumptions and other factors.
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,March 31, 2009, our credit exposure net of collateral was approximately $827$825 million of which approximately 84%89% is to investment grade counterparties. At September 30, 2008,March 31, 2009, our exposure to financial institutions was $145$42 million, which represents 18%5% of our total credit exposure net of collateral (all investment grade).
Regulatory Activity
In February 2009, SWEPCo filed an application with the APSC for a base rate increase of $25 million based on a requested return on equity of 11.5%. SWEPCo also requested a separate rider to recover financing costs related to the construction of the Stall and Turk generating facilities. These financing costs are currently being capitalized as AFUDC in Arkansas. A decision is not expected until the fourth quarter of 2009 or the first quarter of 2010.
In March 2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s ESP filings. If accepted by CSPCo and OPCo, the ESPs would be in effect through 2011. Among other things, the ESP order authorized capped increases to revenues during the three-year ESP period and also authorized a fuel adjustment clause (FAC) which allows CSPCo and OPCo to phase-in and defer actual fuel costs incurred, along with purchased power and related expenses that will be trued-up, subject to annual caps and prudency and accounting reviews. Deferred phase-in regulatory asset balances for fuel costs not currently recovered due to the cap are expected to be material. The projected revenue increases for CSPCo and OPCo are listed below:
| Projected Revenue Increases | |
| 2009 | | 2010 | | 2011 | |
| (in millions) | |
CSPCo | | $ | 116 | | | $ | 109 | | | $ | 116 | |
OPCo | | | 130 | | | | 125 | | | | 153 | |
The above revenues include some incremental cost recoveries. In addition to the revenue increases, net income will be positively affected by the material noncash phase-in deferrals from 2009 through 2011. These deferrals will be collected from 2012 through 2018.
For additional details related to the ESPs, see the “Ohio Electric Security Plan Filings” section of “Significant Factors.”
In March 2009, the IURC approved the settlement agreement with I&M with modifications that provides for an annual increase in revenues of $42 million, including a $19 million increase in revenue from base rates and $23 million in additional tracker revenues for certain incurred costs, subject to true-up.
In March 2009, APCo and WPCo filed an annual ENEC filing with the WVPSC for an increase of approximately $442 million for incremental fuel, purchased power and environmental compliance project expenses, to become effective July 2009. In March 2009, the WVPSC issued an order suspending the rate increase request until December 2009. In April 2009, APCo and WPCo filed a motion for approval of a provisional interim ENEC increase of $156 million, effective July 2009 and subject to refund pending the adjudication of the ENEC by December 2009.
Capital Expenditures
Due to recent creditcapital market instability and the economic slowdown, we are currently reviewingreduced our projections forplanned capital expenditures for 2010 from $3.4 billion to $1.8 billion:
| | 2010 | |
| | Capital Expenditure | |
| | Budget | |
| | (in millions) | |
New Generation | | $ | 251 | |
Environmental | | | 252 | |
Other Generation | | | 431 | |
Transmission | | | 290 | |
Distribution | | | 552 | |
Corporate | | | 70 | |
| | | | |
Total | | $ | 1,846 | |
We also reduced our previous2011 environmental capital expenditure projection of $6.75 billion for 2009 through 2010.from $892 million to $246 million. 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 isintend to keep operation and maintenance expense relatively flat in 2009 as comparedin comparison to 2008. We do not believe that these cutbacks will jeopardize the reliability of the AEP System.
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 Cook Plant Unit 1 (Unit 1) due to turbine vibrations, likely caused by blade failure, which resulted in a fire on the electric generator. This equipment, islocated in the turbine building, and is separate and isolated from the nuclear reactor. The steam turbines that causedRepair of the vibration were installed in 2006property damage 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),turbine rotors and turbine vendorother equipment could cost up 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.approximately $330 million. 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 thatThe treatment of property damage costs, replacement power costs and insurance proceeds will be the subject of future regulatory proceedings in Indiana and Michigan. I&M is repairing Unit 1 couldto resume operations as early as late first quarter/early second quarterOctober 2009 at reduced power. Should post-repair operations prove unsuccessful, the replacement 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 duringparts will extend 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.into 2011.
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 expectedFor 2009, we expect our coal costs to increase by 13% in 2008. We continue to see increases in prices due to expiring lower-priced coalapproximately 12%. With the recent ESP orders for CSPCo and transportation contracts being replaced with higher-priced contracts. WeOPCo, we now 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 requestedmechanisms in all of our jurisdictions. The deferred fuel balances of CSPCo and OPCo at the PUCOend of the ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018. As of March 31, 2009, CSPCo and OPCo had a combined $83 million under-recovered fuel balance, including carrying costs. We expect this amount to reinstate a fuel cost recovery mechanism effective January 1,increase significantly over the remainder of 2009. Fuel cost adjustment rate clauses in our other jurisdictions will help offset future negative impactsDepending upon certain variables, including the potential escalation of fuel price increasescosts and the timing of the economic recovery, this amount may continue to increase in 2010 and 2011.
Recent coal consumption and projected consumption for the remainder of 2009 have decreased significantly. As a result, we are in discussions with our coal suppliers in an effort to better match deliveries with our current consumption trends and to minimize the impact on our gross margins.fuel inventory costs.
RESULTS OF OPERATIONS
Segments
Our principal operating business segments and their related business activities are as follows:
Utility Operations
· | Generation of electricity for sale to U.S. retail and wholesale customers. |
· | Electricity transmission and distribution in the U.S. |
AEP River Operations
· | BargingCommercial barging operations that annually transport approximately 3533 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and Lowerlower Mississippi Rivers. Approximately 39%38% of the barging is for the transportation of agricultural products, 30% for coal, 14%13% for steel and 17%19% for other commodities. Effective July 30, 2008, AEP MEMCO LLC’s name was changed to AEP River Operations LLC. |
Generation and Marketing
· | Wind farms and marketing and risk management activities primarily in ERCOT. |
The table below presents our consolidated Net Income Before Discontinued Operations and Extraordinary Loss by segment for the three and nine months ended September 30, 2008March 31, 2009 and 2007.2008.
| Three Months Ended September 30, | | Nine Months Ended September 30, | |
| 2008 | | 2007 | | 2008 | | 2007 | |
| (in millions) | |
Utility Operations | | $ | 357 | | | $ | 388 | | | $ | 1,030 | | | $ | 879 | |
AEP River Operations | | | 11 | | | | 18 | | | | 21 | | | | 40 | |
Generation and Marketing | | | 16 | | | | 3 | | | | 43 | | | | 17 | |
All Other (a) | | | (10 | ) | | | (2 | ) | | | 133 | | | | (1 | ) |
Income Before Discontinued Operations and Extraordinary Loss | | $ | 374 | | | $ | 407 | | | $ | 1,227 | | | $ | 935 | |
| Three Months Ended March 31, | |
| 2009 | | 2008 | |
| (in millions) | |
Utility Operations | | $ | 346 | | | $ | 413 | |
AEP River Operations | | | 11 | | | | 7 | |
Generation and Marketing | | | 24 | | | | 1 | |
All Other (a) | | | (18 | ) | | | 155 | |
Net Income | | $ | 363 | | | $ | 576 | |
(a) | All Other includes: |
| · | Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. |
| · | Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005. These contracts are financial derivatives which will gradually liquidate and completely expire in 2011. |
| · | The first quarter of 2008 cash settlement of a purchase power and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006. The cash settlement of $255 million ($163 million, net of tax) is included in Net Income. |
| · | Revenue sharing related to the Plaquemine Cogeneration Facility. |
AEP Consolidated
ThirdFirst Quarter of 20082009 Compared to ThirdFirst Quarter of 20072008
Net Income Before Discontinued Operations and Extraordinary Loss in 20082009 decreased $33$213 million compared to 20072008 primarily due to income of $164 million (net of tax) in 2008 from the cash 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 and a decrease in Utility Operations segment earnings of $31$67 million. The decrease in Utility Operations segment earningsnet income 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 retaillower off-system sales margins due to rate increases in Ohio, Virginia, West Virginia, Texaslower sales volumes and Oklahoma.lower market prices which reflect weak market demand.
Average basic shares outstanding increased to 402407 million in 20082009 from 399401 million in 20072008 primarily due to the issuance of shares under our incentive compensation and dividend reinvestment plans. In 2008, we contributed 1.25 million shares of common stock held in treasury to the AEP Foundation. The AEP Foundation is an AEP charitable organization created in 2005 for charitable contributions in the communities in which AEP’s subsidiaries operate. Actual shares outstanding were 403408 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 $292March 31, 2009. In April 2009, we issued 69 million compared to 2007 primarily due to incomeshares of $163 million (netAEP common stock at $24.50 per share for total net proceeds 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.$1.64 billion.
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 SummaryFor the Three and Nine Months Ended September 30, 2008 and 2007
| | | Three Months Ended | |
| | Three Months Ended September 30, | | | Nine Months Ended September 30, | | | March 31, | |
| | 2008 | | | 2007 | | | 2008 | | | 2007 | | | 2009 | | | 2008 | |
| | (in millions) | | | (in millions) | |
Revenues | | $ | 3,968 | | | $ | 3,600 | | | $ | 10,575 | | | $ | 9,587 | | | $ | 3,267 | | | $ | 3,294 | |
Fuel and Purchased Power | | | 1,841 | | | | 1,413 | | | | 4,428 | | | | 3,641 | | | | 1,196 | | | | 1,213 | |
Gross Margin | | | 2,127 | | | | 2,187 | | | | 6,147 | | | | 5,946 | | | | 2,071 | | | | 2,081 | |
Depreciation and Amortization | | | 379 | | | | 374 | | | | 1,099 | | | | 1,122 | | | | 373 | | | | 355 | |
Other Operating Expenses | | | 1,034 | | | | 1,037 | | | | 3,001 | | | | 2,985 | | | | 994 | | | | 941 | |
Operating Income | | | 714 | | | | 776 | | | | 2,047 | | | | 1,839 | | | | 704 | | | | 785 | |
Other Income, Net | | | 46 | | | | 27 | | | | 135 | | | | 72 | | | | 30 | | | | 43 | |
Interest Charges and Preferred Stock Dividend Requirements | | | 225 | | | | 213 | | | | 653 | | | | 599 | | |
Interest Charges | | | | 220 | | | | 208 | |
Income Tax Expense | | | 178 | | | | 202 | | | | 499 | | | | 433 | | | | 168 | | | | 207 | |
Income Before Discontinued Operations and Extraordinary Loss | | $ | 357 | | | $ | 388 | | | $ | 1,030 | | | $ | 879 | | |
Net Income | | | $ | 346 | | | $ | 413 | |
Summary of Selected Sales and Weather Data
For Utility Operations
For the Three and Nine Months Ended September 30,March 31, 2009 and 2008 and 2007
| | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
Energy/Delivery Summary | | 2008 | | | 2007 | | | 2008 | | | 2007 | |
| | (in millions of KWH) | |
Energy | | | | | | | | | | | | |
Retail: | | | | | | | | | | | | |
Residential | | | 12,754 | | | | 13,749 | | | | 37,084 | | | | 38,015 | |
Commercial | | | 10,794 | | | | 11,164 | | | | 30,249 | | | | 30,750 | |
Industrial | | | 14,761 | | | | 14,697 | | | | 44,171 | | | | 43,110 | |
Miscellaneous | | | 668 | | | | 686 | | | | 1,916 | | | | 1,932 | |
Total Retail | | | 38,977 | | | | 40,296 | | | | 113,420 | | | | 113,807 | |
| | | | | | | | | | | | | | | | |
Wholesale | | | 13,130 | | | | 13,493 | | | | 35,728 | | | | 31,648 | |
| | | | | | | | | | | | | | | | |
Delivery | | | | | | | | | | | | | | | | |
Texas Wires – Energy delivered to customers served by AEP’s Texas Wires Companies | | | 7,961 | | | | 7,721 | | | | 20,916 | | | | 20,297 | |
Total KWHs | | | 60,068 | | | | 61,510 | | | | 170,064 | | | | 165,752 | |
| | 2009 | | | 2008 | |
Energy Summary | | (in millions of KWH) | |
Retail: | | | | | | |
Residential | | | 14,368 | | | | 14,500 | |
Commercial | | | 9,395 | | | | 9,547 | |
Industrial | | | 12,126 | | | | 14,350 | |
Miscellaneous | | | 576 | | | | 609 | |
Total Retail | | | 36,465 | | | | 39,006 | |
| | | | | | | | |
Wholesale | | | 6,777 | | | | 11,742 | |
| | | | | | | | |
Texas Wires – Energy Delivered to Customers Served by TNC and TCC in ERCOT | | | 5,738 | | | | 5,823 | |
Total KWHs | | | 48,980 | | | | 56,571 | |
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. Cooling degree days and heating degree days in our service territory for the three months ended March 31, 2009 and 2008 were as follows:
Summary of Heating and Cooling Degree Days for Utility Operations
For the Three and Nine Months Ended September 30, 2008 and 2007 | | 2009 | | | 2008 | |
Weather Summary | | (in degree days) | |
Eastern Region | | | | | | |
Actual – Heating (a) | | | 1,900 | | | | 1,830 | |
Normal – Heating (b) | | | 1,791 | | | | 1,767 | |
| | | | | | | | |
Actual – Cooling (c) | | | 5 | | | | - | |
Normal – Cooling (b) | | | 3 | | | | 3 | |
| | | | | | | | |
Western Region (d) | | | | | | | | |
Actual – Heating (a) | | | 854 | | | | 941 | |
Normal – Heating (b) | | | 905 | | | | 931 | |
| | | | | | | | |
Actual – Cooling (c) | | | 38 | | | | 26 | |
Normal – Cooling (b) | | | 20 | | | | 20 | |
| | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | 2008 | | | 2007 | | | 2008 | | | 2007 | |
| | (in degree days) | |
Weather Summary | | | | | | | | | | | | |
Eastern Region | | | | | | | | | | | | |
Actual – Heating (a) | | | - | | | | 2 | | | | 1,960 | | | | 2,041 | |
Normal – Heating (b) | | | 7 | | | | 7 | | | | 1,950 | | | | 1,973 | |
| | | | | | | | | | | | | | | | |
Actual – Cooling (c) | | | 651 | | | | 808 | | | | 924 | | | | 1,189 | |
Normal – Cooling (b) | | | 687 | | | | 685 | | | | 969 | | | | 963 | |
| | | | | | | | | | | | | | | | |
Western Region (d) | | | | | | | | | | | | | | | | |
Actual – Heating (a) | | | - | | | | - | | | | 989 | | | | 994 | |
Normal – Heating (b) | | | 2 | | | | 2 | | | | 967 | | | | 993 | |
| | | | | | | | | | | | | | | | |
Actual – Cooling (c) | | | 1,250 | | | | 1,406 | | | | 1,951 | | | | 2,084 | |
Normal – Cooling (b) | | | 1,402 | | | | 1,411 | | | | 2,074 | | | | 2,084 | |
(a) | Eastern region and western region heating degree days are calculated on a 55 degree temperature base. |
(b) | Normal Heating/Cooling represents the thirty-year average of degree days. |
(c) | Eastern region and western region cooling degree days are calculated on a 65 degree temperature base. |
(d) | Western region statistics represent PSO/SWEPCo customer base only. |
ThirdFirst Quarter of 20082009 Compared to ThirdFirst Quarter of 20072008
Reconciliation of ThirdFirst Quarter of 20072008 to ThirdFirst Quarter of 20082009
Net Income from Utility Operations Before Discontinued Operations and Extraordinary Loss
(in millions)
Third Quarter of 2007 | | | | | $ | 388 | |
| | | | | | | |
Changes in Gross Margin: | | | | | | | |
Retail Margins | | | (81 | ) | | | | |
Off-system Sales | | | (7 | ) | | | | |
Transmission Revenues | | | 4 | | | | | |
Other | | | 24 | | | | | |
Total Change in Gross Margin | | | | | | | (60 | ) |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | - | | | | | |
Depreciation and Amortization | | | (5 | ) | | | | |
Taxes Other Than Income Taxes | | | 2 | | | | | |
Carrying Costs Income | | | 7 | | | | | |
Interest Income | | | 8 | | | | | |
Other Income, Net | | | 5 | | | | | |
Interest and Other Charges | | | (12 | ) | | | | |
Total Change in Operating Expenses and Other | | | | | | | 5 | |
| | | | | | | | |
Income Tax Expense | | | | | | | 24 | |
| | | | | | | | |
Third Quarter of 2008 | | | | | | $ | 357 | |
First Quarter of 2008 | | | | | $ | 413 | |
| | | | | | | |
Changes in Gross Margin: | | | | | | | |
Retail Margins | | | 61 | | | | | |
Off-system Sales | | | (136 | ) | | | | |
Transmission Revenues | | | 4 | | | | | |
Other Revenues | | | 61 | | | | | |
Total Change in Gross Margin | | | | | | | (10 | ) |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | (56 | ) | | | | |
Gain on Dispositions of Assets, Net | | | 3 | | | | | |
Depreciation and Amortization | | | (18 | ) | | | | |
Interest Income | | | (10 | ) | | | | |
Carrying Costs Income | | | (8 | ) | | | | |
Other Income, Net | | | 5 | | | | | |
Interest Expense | | | (12 | ) | | | | |
Total Change in Operating Expenses and Other | | | | | | | (96 | ) |
| | | | | | | | |
Income Tax Expense | | | | | | | 39 | |
| | | | | | | | |
First Quarter of 2009 | | | | | | $ | 346 | |
Net Income from Utility Operations Before Discontinued Operations and Extraordinary Loss decreased $31$67 million to $357$346 million in 2008.2009. The key drivers of the decrease were a $60$10 million decrease in Gross Margin offset byand a $5$96 million decreaseincrease in Operating Expenses and Other, andpartially offset by a $24$39 million decrease in Income Tax Expense.
The major components of the net decrease in Gross Margin were as follows:
· | Retail Margins decreased $81increased $61 million primarily due to the following: |
| · | A $78$58 million increase related to base rates and recovery of E&R costs in Virginia and construction financing costs in West Virginia, a $17 million increase in base rates in Oklahoma, a $13 million increase related to increased fuelthe net increases in Ohio as a result of the PUCO’s approval of our Ohio ESPs and consumable expenses in Ohio. CSPCo and OPCo have applieda $5 million net rate increase for an active fuel clause in their Ohio ESP to be effective January 1, 2009. I&M. |
| · | An $80A $54 million decreaseincrease resulting from reduced sharing of off-system sales margins with retail customers in usage primarilyour eastern service territory due to a 19% decrease in cooling degree daystotal off-system sales. |
| · | A $6 million increase in our eastern region, an 11% decreasefuel margins in cooling degree daysOhio due to the deferral of fuel costs by CSPCo and OPCo in our western region as well as outages caused by Hurricanes Dolly, Gustav2009. The PUCO’s March 2009 approval of CSPCo’s and Ike. Approximately 17%OPCo’s ESPs allows for the recovery of our reduction in load was attributable to these storms.fuel and related costs during the ESP period. See “Ohio Electric Security Plan Filings” section of Note 3. |
| These decreasesincreases were partially offset by: |
| · | A $61$58 million increasedecrease in fuel margins related to net rate increases implementedan OPCo coal contract amendment recorded in our Ohio jurisdictions, an $8 million increase related2008 which reduced future deliveries to recovery of E&R costsOPCo in Virginia and the construction financing costs rider in West Virginia, a $6 million increase in base rates in Texas and a $6 million increase in base rates in Oklahoma.exchange for consideration received. |
| · | A $9$32 million increasedecrease in margins from industrial sales due to reduced shifts and suspended operations by some of the large industrial customers in our service territories. |
| · | A $20 million decrease in fuel margins due to higher fuel and purchased power costs related to increased usagethe Cook Plant Unit 1 shutdown. This decrease in fuel margins was offset by Ormet, an industrial customera corresponding increase in Ohio. See “Ormet” section of Note 3.Other Revenues as discussed below. |
· | Margins from Off-system Sales decreased $7$136 million primarily due to lower tradingphysical sales volumes and lower margins and the favorable effects of a fuel reconciliation recorded in our westerneastern service territory in the third quarter of 2007,reflecting lower market prices, partially offset by increases in East physical off-system sales margins due mostly to higher prices.trading margins. |
· | TransmissionOther Revenues increased $4$61 million primarily due to increased rates inCook Plant accidental outage insurance policy proceeds of $54 million. Of these insurance proceeds, $20 million were used to offset fuel costs associated with the SPP region. |
· | Other revenues increased $24 million primarily due to increased third-party engineering and construction work and anCook Plant Unit 1 shutdown. This increase in pole attachment revenue.revenues was offset by a corresponding decrease in Retail Margins as discussed above. See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4. |
Utility Operating Expenses and Other and Income Taxes changed between years as follows:
· | Other Operation and Maintenance expenses were flat in comparison to 2007. We experienced decreases related to the following: |
| · | A $77 million decrease related to the recording of the NSR settlement in the third quarter of 2007. We are evaluating methods to pursue recovery in all of our affected jurisdictions. |
| · | A $9 million decrease related to the establishment of a regulatory asset in the third quarter of 2008 for Virginia’s share of previously expended NSR settlement costs. |
| These decreases were offset by: |
| · | A $24 million increase in non-storm system improvements, customer work and other distribution expenses. |
| · | A $21 million increase in storm restoration costs, primarily related to Hurricanes Dolly, Gustav and Ike. |
| · | A $15 million increase in recoverable PJM expenses in Ohio. |
| · | A $10 million increase in generation plant maintenance. |
| · | An $8 million increase in recoverable customer account expenses related to the Universal Service Fund for Ohio customers who qualify for payment assistance. |
| · | An $8 million increase in transmission expenses for tree trimming and reliability. |
· | Depreciation and Amortization expense increased $5 million primarily due to higher depreciable property balances from the installation of environmental upgrades. |
· | Carrying Costs Income increased $7 million primarily due to increased carrying cost income on cost deferrals in Virginia and Oklahoma. |
· | Interest Income increased $8 million primarily due to the favorable effect of claims for refund filed with the IRS. |
· | Interest and Other Charges increased $12 million primarily due to additional debt issued and higher interest rates on variable rate debt. |
· | Income Tax Expense decreased $24 million due to a decrease in pretax income. |
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)
Nine Months Ended September 30, 2007 | | | | | $ | 879 | |
| | | | | | | |
Changes in Gross Margin: | | | | | | | |
Retail Margins | | | 79 | | | | | |
Off-system Sales | | | 73 | | | | | |
Transmission Revenues | | | 22 | | | | | |
Other Revenues | | | 27 | | | | | |
Total Change in Gross Margin | | | | | | | 201 | |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | 11 | | | | | |
Gain on Dispositions of Assets, Net | | | (18 | ) | | | | |
Depreciation and Amortization | | | 23 | | | | | |
Taxes Other Than Income Taxes | | | (9 | ) | | | | |
Carrying Costs Income | | | 26 | | | | | |
Interest Income | | | 25 | | | | | |
Other Income, Net | | | 12 | | | | | |
Interest and Other Charges | | | (54 | ) | | | | |
Total Change in Operating Expenses and Other | | | | | | | 16 | |
| | | | | | | | |
Income Tax Expense | | | | | | | (66 | ) |
| | | | | | | | |
Nine Months Ended September 30, 2008 | | | | | | $ | 1,030 | |
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:
· | Retail Margins increased $79$56 million primarily due to the following: |
| · | A $148An $80 million increase related to net rate increases implementedthe deferral of Oklahoma ice storm costs in our Ohio jurisdictions, a $39 million increase related to2008 resulting from an OCC order approving recovery of E&R costs in VirginiaJanuary and the construction financing costs rider in West Virginia, a $20 million increase in base rates in Oklahoma and a $17 million increase in base rates in Texas.December 2007 ice storm expenses. |
| · | A $42$38 million increase related to increased usage by Ormet, an industrial customerstorm restoration expenses, primarily in Ohio. See “Ormet” section of Note 3.our eastern service territory. |
| · | A $37$15 million net increase due to adjustments recorded in the prior year related to an obligation to contribute to the 2007 Virginia base rate case which included a second quarter 2007 provision“Partnership with Ohio” fund for revenue refund. |
| · | A $29 million increase due to coal contract amendments in 2008.low income, at-risk customers ordered by the PUCO’s March 2009 approval of CSPCo’s and OPCo’s ESPs. See “Ohio Electric Security Plan Filings” section of Note 3. |
| These increases were partially offset by: |
| · | A $164 million decrease related to increased fuel and consumable expenses in Ohio. CSPCo and OPCo have applied for an active fuel clause in their Ohio ESP to be effective January 1, 2009. |
| · | A $65$34 million decrease in usage primarily due to a 22% decrease in cooling degree days in our eastern region and a 6% decrease in cooling degree days in our western region.
|
| · | A $29 million increase in the sharing of off-system sales margins with customers due to an increase in total off-system sales.
|
· | Margins from Off-system Sales increased $73 million primarily due to higher physical off-system sales in our eastern territory as the result of higher volumes and higher prices, aided by additional generation available in 2008 due to fewer planned outages and lower internal load. This increase was partially offset by lower trading margins and the favorable effects of a fuel reconciliation recorded in our western territory in the third quarter of 2007. |
· | Transmission Revenues increased $22 million primarily due to increased rates in the ERCOT and SPP regions. |
· | Other Revenues increased $27 million primarily due to increased third-party engineering and construction work, an increase in pole attachment revenue and the recording of an unfavorable provision for TCC for the refund of bonded rates recorded in 2007. |
Utility Operating Expenses and Other and Income Taxes changed between years as follows:
· | Other Operation and Maintenance expenses decreased $11 million primarily due to the following:employee-related expenses. |
| · | A $77$14 million decrease related to the recording of NSR settlement costs in September 2007. We are evaluating methods to pursue recovery in all of our affected jurisdictions.plant outage and other maintenance expenses. |
| · | A $62$13 million decrease related to the deferral of Oklahoma storm restoration costs in the first quarter of 2008, net of amortization, as a result of a rate settlement to recover 2007 storm restoration costs. |
| · | A $19 million decrease in generation plant removal costs. |
| These decreases were partially offset by: |
| · | A $33 million increase in tree trimming, reliability and system improvement expense. |
| · | A $29 million increase in recoverable PJM expenses in Ohio. |
| · | A $23 million increase in generation plant operationsother transmission and maintenance expense. |
| · | A $21 million increase in recoverable customer account expenses related to the Universal Service Fund for Ohio customers who qualify for payment assistance. |
| · | A $16 million increase in storm restoration costs, primarily related to Hurricanes Dolly, Gustav and Ike, which occurred in the third quarter of 2008. |
| · | A $16 million increase in maintenance expense at the Cook Plant.distribution expenses. |
| · | A $10 million increasedecrease related to the write-off of the unrecoverable pre-construction costs for PSO’s cancelled Red Rock Generating Facility in the first quarter of 2008. |
· | Gain on Disposition of Assets, Net decreasedDepreciation and Amortization increased $18 million primarily due to the expiration of the earnings sharing agreement with Centrica from the sale of our Texas REPs in 2002. In 2007, we received the final earnings sharing payment of $20 million. |
· | Depreciation and Amortization expense decreased $23 million primarily due to lower commission-approved depreciation rates in Indiana, Michigan, Oklahoma and Texas and lower Ohio regulatory asset amortization, partially offset by higher depreciable property balances as the result of environmental improvements placed in service at OPCo and prior year adjustmentsvarious other property additions and higher depreciation rates for OPCo related to the Virginia base rate case. |
· | Taxes Other Than Income Taxes increased $9 million primarily due to favorable adjustments to property tax returns recorded in the prior year. |
· | Carrying Costs Income increased $26 million primarily due to increased carrying cost income on cost deferrals in Virginia and Oklahoma.shortened depreciable lives for certain generating facilities. |
· | Interest Income increased $25decreased $10 million primarily due to the 2008 favorable effect of claims for refund filed with the IRS. |
· | OtherCarrying Costs Income Netdecreased $8 million primarily due to the completion of reliability deferrals in Virginia in December 2008 and the decrease of environmental deferrals in Virginia in 2009. |
· | Interest Expense increased $12 million primarily due to an increase in the equity component of AFUDC as a result of new generation projects. |
· | Interest and Other Charges increased $54 million primarily due to additionallong-term debt issued and higher interest rates on variable rate debt. |
· | Income Tax Expense increased $66decreased $39 million due to an increasea decrease in pretax income. |
AEP River Operations
ThirdFirst Quarter of 20082009 Compared to ThirdFirst Quarter of 20072008
Net Income Before Discontinued Operations and Extraordinary Loss from our AEP River Operations segment decreasedincreased from $7 million in 2008 to $11 million in 2008 from $18 million in 20072009 primarily due to significant disruptions of ship arrivalslower fuel costs 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 floodinggains 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,sale of two older towboats. These increases were 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 primarilylower revenues due to significant flooding on various inland waterways throughout 2008reduced import volumes 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.rates.
Generation and Marketing
ThirdFirst Quarter of 20082009 Compared to ThirdFirst Quarter of 20072008
Net Income Before Discontinued Operations and Extraordinary Loss from our Generation and Marketing segment increased to $16from $1 million in 2008 from $3to $24 million in 20072009 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.
activities.
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
ThirdFirst Quarter of 20082009 Compared to ThirdFirst Quarter of 20072008
Loss Before Discontinued Operations and Extraordinary LossNet Income from All Other increased to $10decreased from income of $155 million in 2008 from $2to a loss of $18 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 2007.2009. In 2008, we had after-tax income of $163$164 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$114 million in the thirdfirst quarter of 20082009 compared to the thirdfirst quarter of 20072008 primarily due to a decrease in pretax income.
Income Tax Expense increased $165 million in the nine-month period ended September 30, 2008 compared to the nine-month period ended September 30, 2007 primarily due to an increase in pretaxbook income.
FINANCIAL CONDITION
We measure our financial condition by the strength of our balance sheet and the liquidity provided by our cash flows.
Debt and Equity CapitalizationDebt and Equity Capitalization | | | | | |
| | September 30, 2008 | | | December 31, 2007 | | | March 31, 2009 | | December 31, 2008 |
| | ($ in millions) | | | ($ in millions) |
Long-term Debt, including amounts due within one year | | $ | 16,007 | | | | 56.6 | % | | $ | 14,994 | | | | 58.1 | % | | $ | 16,843 | | 56.5% | | $ | 15,983 | | 55.6% |
Short-term Debt | | | 1,302 | | | | 4.6 | | | | 660 | | | | 2.6 | | | | 1,976 | | 6.6 | | | 1,976 | | 6.9 |
Total Debt | | | 17,309 | | | | 61.2 | | | | 15,654 | | | | 60.7 | | | 18,819 | | 63.1 | | 17,959 | | 62.5 |
Common Equity | | | 10,917 | | | | 38.6 | | | | 10,079 | | | | 39.1 | | |
Preferred Stock | | | 61 | | | | 0.2 | | | | 61 | | | | 0.2 | | |
Preferred Stock of Subsidiaries | | | 61 | | 0.2 | | 61 | | 0.2 |
AEP Common Equity | | | 10,940 | | 36.6 | | 10,693 | | 37.2 |
Noncontrolling Interests | | | | 18 | | 0.1 | | | 17 | | 0.1 |
| | | | | | | | | | | | | | | | | | | | | | | | |
Total Debt and Equity Capitalization | | $ | 28,287 | | | | 100.0 | % | | $ | 25,794 | | | | 100.0 | % | | $ | 29,838 | | 100.0% | | $ | 28,730 | | 100.0% |
OurAs of March 31, 2009, our ratio of debt to totaldebt-to-total capital increased from 60.7% to 61.2% in 2008 due to ourwas 63.1%. After the issuance of 69 million new common shares and the application of the net proceeds of $1.64 billion to reduce debt, to fund construction and our strategy to deal withpro forma ratio of debt-to-capital as of the credit situation by drawing cash from our credit facilities.date of issuance would have been 57.6%.
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 andor common stock.
CreditCapital Markets
In recent months,2008, the domestic and world economies experienced significant slowdowns. The financial markets have become increasingly unstable and constrainedremain volatile at both a global and domestic level. This systemic marketplace distress is impactingcould impact our access to capital, our liquidity and our cost of capital. The uncertainties in the creditcapital markets could have significant implications on our subsidiaries since theywe 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 theits 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
We believe that we have adequate liquidity through 2009 under our existing credit facilities. However, the current credit markets could constrain our ability to issue commercial paper. Approximately $300 million (excluding payments due for securitization bonds which we recover directly from ratepayers) of our $17 billion of long-term debt as of March 31, 2009 will mature during the remainder of 2009. We intend to refinance debt maturities. At March 31, 2009, we had $3.9 billion ($3.6 billion after an April expiration of one facility) in aggregate credit facility commitments to support our planned business operations and construction program through 2009.operations. These commitments include 27 different banks with no one bank having more than 10% of our total bank commitments.
InDuring the first quarter of 2009, we issued $475 million of 7% senior notes due 2019, $350 million of 7.95% senior notes due 2020, $100 million of 6.25% Pollution Control Bonds due 2025 and $34 million of 5.25% Pollution Control Bonds due 2014.
During 2008, we chose to begin eliminating our auction-rate debt position 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 ratingsconditions. As of those insurers were downgraded or placed on negative outlook. These market factors contributed to higher interest rates in successful auctions and increasing occurrencesMarch 31, 2009, $272 million of failed auctions forour auction-rate 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%1.676% and 13%) thatremained outstanding with rates 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, $367Approximately $218 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$272 million of our reacquired auction rate tax-exempt long-termoutstanding auction-rate debt whichrelates to a lease structure with JMG that we planare unable to reissuerefinance without JMG’s consent. The rates for this debt are at contractual maximum rates of 13%. The initial term for the JMG lease structure matures on March 31, 2010. We are evaluating whether to terminate this facility prior to maturity. Termination of this facility requires approval from the public as market conditions permit.PUCO.
Credit Facilities
We manage our liquidity by maintaining adequate external financing commitments. At September 30, 2008,March 31, 2009, our available liquidity was approximately $3$2.2 billion as illustrated in the table below:
| | Amount | | Maturity |
| | (in millions) | | |
Commercial Paper Backup: | | | | |
Revolving Credit Facility | | $ | 1,500 | | March 2011 |
Revolving Credit Facility | | | 1,454 | (a) | April 2012 |
Revolving Credit Facility | | | 627 | (a) | April 2011 |
Revolving Credit Facility | | | 338 | (a) | April 2009 |
Total | | | 3,919 | | |
Short-term Investments | | | 490 | | |
Cash and Cash Equivalents | | | 338 | | |
Total Liquidity Sources | | | 4,747 | | |
Less: AEP Commercial Paper Outstanding | | | 701 | | |
Cash Drawn on Credit Facilities | | | 591 | | |
Letters of Credit Drawn | | | 439 | | |
| | | | | |
Net Available Liquidity | | $ | 3,016 | | |
| | Amount | | | Maturity |
| | (in millions) | | | |
Commercial Paper Backup: | | | | | |
Revolving Credit Facility | | $ | 1,500 | | | March 2011 |
Revolving Credit Facility | | | 1,454 | | (a) | April 2012 |
Revolving Credit Facility | | | 627 | | (a) | April 2011 |
Revolving Credit Facility | | | 338 | | (a)(b) | April 2009 |
Total | | | 3,919 | | | |
Cash and Cash Equivalents | | | 710 | | | |
Total Liquidity Sources | | | 4,629 | | | |
Less: Cash Drawn on Credit Facilities | | | 1,969 | | (c) | |
Letters of Credit Issued | | | 492 | | | |
| | | | | | |
Net Available Liquidity | | $ | 2,168 | | | |
(a) | Reduced by Lehman Brothers Holdings Inc.’s commitment amount of $81 million following its bankruptcy. |
(b) | Expired in April 2009. |
(c) | Paid $1.25 billion with proceeds from the equity issuance in April 2009. |
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, theThe credit facilities were amended so thatallow for the issuance of up to $750 million may be issuedas letters of credit under each credit facility as letters of credit.facility.
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,March 31, 2009, we had credit facilities totaling $3 billion to support our commercial paper program. In 2008, we borrowed $2 billion under these credit facilities at a LIBOR rate. In April 2009, we repaid $1.25 billion of the $2 billion borrowed under the credit facilities. The maximum amount of commercial paper outstanding during the first nine months of 20082009 was $1.2 billion.$308 million. The weighted-average interest rate offor our commercial paper during the first nine months of 20082009 was 3.25%1.22%. No commercial paper was outstanding at March 31, 2009.
In April 2008, we entered into aAs of March 31, 2009, under the $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 ofbankruptcy, letters of credit of $372 million were issued under the 3-year credit agreement to support variable rate demand notes.Pollution Control Bonds.
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,March 31, 2009, this contractually-defined percentage was 57.3%59.1%. Nonperformance of these covenants could result in an event of default under these credit agreements. At September 30, 2008,March 31, 2009, 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.
OurThe revolving credit facilities do not permit the lenders to refuse a draw on anyeither 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,March 31, 2009, 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 1910.1910, representing 396 consecutive quarters. The Board of Directors declared a quarterly dividend of $0.41 per share in October 2008.April 2009. 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 areas of March 31, 2009 were as follows:
| | Moody’s | | | S&P | | | Fitch | |
| | | | | | | | | |
AEP Short-term Debt | | P-2 | | | A-2 | | | F-2 | |
AEP Senior Unsecured Debt | | Baa2 | | | BBB | | | BBB | |
If we or any of our rated subsidiaries receive an upgrade from any of the rating agencies listed above, our borrowing costs could decrease. In 2009, Moody’s:
· | Placed AEP on negative outlook due to concern about overall credit worthiness, pending rate cases and recessionary pressures. |
· | Placed OPCo, SWEPCo, TCC and TNC on review for possible downgrade due to concerns about financial metrics and pending cost and construction recoveries. |
· | Affirmed the stable rating outlooks for CSPCo, I&M, KPCo and PSO. |
· | Changed the rating outlook for APCo from negative to stable due to recent rate recoveries in Virginia and West Virginia. |
In 2009, Fitch:
· | Affirmed its stable rating outlook for I&M, PSO and TNC. |
· | Changed its rating outlook for TCC from stable to negative. |
If we receive a downgrade in our credit ratings by oneany 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.
| Nine Months Ended | | Three Months Ended | |
| September 30, | | March 31, | |
| 2008 | | 2007 | | 2009 | | 2008 | |
| (in millions) | | (in millions) | |
Cash and Cash Equivalents at Beginning of Period | | $ | 178 | | | $ | 301 | | | $ | 411 | | | $ | 178 | |
Net Cash Flows from Operating Activities | | | 2,053 | | | | 1,630 | | | | 317 | | | | 631 | |
Net Cash Flows Used for Investing Activities | | | (3,061 | ) | | | (2,935 | ) | | | (727 | ) | | | (894 | ) |
Net Cash Flows from Financing Activities | | | 1,168 | | | | 1,200 | | | | 709 | | | | 240 | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 160 | | | | (105 | ) | | | 299 | | | | (23 | ) |
Cash and Cash Equivalents at End of Period | | $ | 338 | | | $ | 196 | | | $ | 710 | | | $ | 155 | |
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
| Nine Months Ended | |
| September 30, | |
| 2008 | | 2007 | |
| (in millions) | |
Net Income | | $ | 1,228 | | | $ | 858 | |
Less: Discontinued Operations, Net of Tax | | | (1 | ) | | | (2 | ) |
Income Before Discontinued Operations | | | 1,227 | | | | 856 | |
Depreciation and Amortization | | | 1,123 | | | | 1,144 | |
Other | | | (297 | ) | | | (370 | ) |
Net Cash Flows from Operating Activities | | $ | 2,053 | | | $ | 1,630 | |
| Three Months Ended | |
| March 31, | |
| 2009 | | 2008 | |
| (in millions) | |
Net Income | | $ | 363 | | | $ | 576 | |
Depreciation and Amortization | | | 382 | | | | 363 | |
Other | | | (428 | ) | | | (308 | ) |
Net Cash Flows from Operating Activities | | $ | 317 | | | $ | 631 | |
Net Cash Flows from Operating Activities increaseddecreased in 20082009 primarily due to the TEM settlement.a decline in net income and an increase in fuel inventory.
Net Cash Flows from Operating Activities were $2.1 billion$317 million in 20082009 consisting primarily of Net Income Before Discontinued Operations of $1.2 billion$363 million and $1.1 billion$382 million of noncash Depreciationdepreciation and Amortization.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 an increase in coal inventory from December 31, 2008.
Net Cash Flows from Operating Activities were $631 million in 2008 consisting primarily of Net Income of $576 million and $363 million of noncash depreciation and amortization. Other represents items that had a numbercurrent 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 payment of items the most significant of which relates primarily to the Texas CTC refund of fuel over-recovery.accrued at December 31, 2007.
Investing Activities
| Nine Months Ended | |
| September 30, | |
| 2008 | | 2007 | |
| (in millions) | |
Construction Expenditures | | $ | (2,576 | ) | | $ | (2,595 | ) |
Purchases/Sales of Investment Securities, Net | | | (474 | ) | | | 217 | |
Acquisition of Assets | | | (97 | ) | | | (512 | ) |
Proceeds from Sales of Assets | | | 83 | | | | 78 | |
Other | | | 3 | | | | (123 | ) |
Net Cash Flows Used for Investing Activities | | $ | (3,061 | ) | | $ | (2,935 | ) |
| Three Months Ended | |
| March 31, | |
| 2009 | | 2008 | |
| (in millions) | |
Construction Expenditures | | $ | (897 | ) | | $ | (778 | ) |
Proceeds from Sales of Assets | | | 172 | | | | 18 | |
Other | | | (2 | ) | | | (134 | ) |
Net Cash Flows Used for Investing Activities | | $ | (727 | ) | | $ | (894 | ) |
Net Cash Flows Used for Investing Activities were $3.1 billion$727 million in 2009 and $894 million in 2008 primarily due to Construction Expenditures for our environmental, distribution and new generation, environmental and distribution investment plan.
Net Cash Flows Used for Investing Activities were $2.9 billion in 2007 primarily Construction Expenditures increased compared to 2008 due to Construction Expendituresexpenditures for our environmental, distribution and new generation investment plan. We paid $512during 2009. Proceeds from Sales of Assets in 2009 primarily includes $104 million to purchase gas-fired generating units to acquire capacity at a cost below that of building a new, comparable plant.in progress payments for Turk Plant construction from the joint owners.
In our normal course of business, we purchase and sell investment securities including variable rate demand notes with cash available for short-term investments including the cash drawn against our credit facilities in 2008. We alsoand purchase and sell investment securities within our nuclear trusts. The net amount of these activities is included in Other.
We forecast approximately $1.2$2.6 billion of construction expenditures for the remainderall of 2008.2009, excluding AFUDC. 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 operationsnet income and financing activities.
Financing Activities
| Nine Months Ended | |
| September 30, | |
| 2008 | | 2007 | |
| (in millions) | |
Issuance of Common Stock | | $ | 106 | | | $ | 116 | |
Issuance/Retirement of Debt, Net | | | 1,621 | | | | 1,623 | |
Dividends Paid on Common Stock | | | (494 | ) | | | (467 | ) |
Other | | | (65 | ) | | | (72 | ) |
Net Cash Flows from Financing Activities | | $ | 1,168 | | | $ | 1,200 | |
| Three Months Ended | |
| March 31, | |
| 2009 | | 2008 | |
| (in millions) | |
Issuance of Common Stock | | $ | 48 | | | $ | 45 | |
Issuance/Retirement of Debt, Net | | | 854 | | | | 376 | |
Dividends Paid on Common Stock | | | (169 | ) | | | (167 | ) |
Other | | | (24 | ) | | | (14 | ) |
Net Cash Flows from Financing Activities | | $ | 709 | | | $ | 240 | |
Net Cash Flows from Financing Activities in 20082009 were $1.2 billion$709 million primarily due to the issuance of additional debt including $315$825 million of Junior Subordinated Debenturessenior unsecured notes and a net increase of $1.3 billion in outstanding Senior Unsecured Notes partially offset, by the reacquisition of a net $370$134 million of Pollution Control Bonds and $125 million of Securitization Bonds. In September 2008, we borrowed $600 million under our credit agreements.pollution control bonds. See Note 9 – Financing Activities for a complete discussion of long-term debt issuances and retirements.
Net Cash Flows from Financing Activities in 20072008 were $1.2 billion$240 million primarily due to issuing $1.9 billionthe issuance of debt securities including $1 billion$315 million of new debt for plant acquisitionsjunior subordinated debentures and construction$500 million of senior unsecured notes, partially offset by the retirement of $95 million of pollution control bonds, $52 million of senior unsecured notes and increasing$34 million of mortgage notes and the reduction of our short-term commercial paper borrowings.outstanding by $251 million.
Our capital investment plans for the remainder of 2009 will require additional funding from the capital markets.
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:
| September 30, 2008 | | December 31, 2007 | |
| (in millions) | |
AEP Credit Accounts Receivable Purchase Commitments | | $ | 555 | | | $ | 507 | |
Rockport Plant Unit 2 Future Minimum Lease Payments | | | 2,142 | | | | 2,216 | |
Railcars Maximum Potential Loss From Lease Agreement | | | 26 | | | | 30 | |
| March 31, 2009 | | December 31, 2008 | |
| (in millions) |
AEP Credit Accounts Receivable Purchase Commitments | | $ | 578 | | | $ | 650 | |
Rockport Plant Unit 2 Future Minimum Lease Payments | | | 2,070 | | | | 2,070 | |
Railcars Maximum Potential Loss From Lease Agreement | | | 25 | | | | 25 | |
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 20072008 Annual Report.
Summary Obligation Information
A summary of our contractual obligations is included in our 20072008 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 20072008 Annual Report. The 20072008 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 20072008 Annual Report, but may have a material impact on our future net income, cash flows and financial condition.
Ohio Electric Security Plan Filings
In March 2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s ESPs which will be in effect through 2011. The ESP order authorized increases to revenues during the ESP period and capped the overall revenue increases through a phase-in of the fuel adjustment clause (FAC). The ordered increases for CSPCo are 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo are 8% in 2009, 7% in 2010 and 8% in 2011. After final PUCO review and approval of conforming rate schedules, CSPCo and OPCo implemented rates for the April 2009 billing cycle. CSPCo and OPCo will collect the 2009 annualized revenue increase over the remainder of 2009.
The order provides a FAC for the three-year period of the ESP. The FAC increase will be phased in to meet the ordered annual caps described above. The FAC increase before phase-in will be subject to quarterly true-ups to actual recoverable FAC costs and to annual accounting audits and prudency reviews. The order allows CSPCo and OPCo to defer unrecovered FAC costs resulting from the annual caps/phase-in plan and to accrue carrying charges on such deferrals at CSPCo’s and OPCo’s weighted average cost of capital. The deferred FAC balance at the end of the ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018. As of March 31, 2009, the FAC deferral balances were $17 million and $66 million for CSPCo and OPCo, respectively, including carrying charges. The PUCO rejected a proposal by several intervenors to offset the FAC costs with a credit for off-system sales margins. As a result, CSPCo and OPCo will retain the benefit of their share of the AEP System’s off-system sales. In addition, the ESP order provided for both the FAC deferral credits and the off-system sales margins to be excluded from the methodology for the Significantly Excessive Earnings Test (SEET). The SEET is discussed below.
Additionally, the order addressed several other items, including:
· | The approval of new distribution riders, subject to true-up for recovery of costs for enhanced vegetation management programs for CSPCo and OPCo and the proposed gridSMART advanced metering initial program roll out in a portion of CSPCo’s service territory. The PUCO proposed that CSPCo mitigate the costs of gridSMART by seeking matching funds under the American Recovery and Reinvestment Act of 2009. As a result, a rider was established to recover 50% or $32 million of the projected $64 million revenue requirement related to gridSMART costs. The PUCO denied the other distribution system reliability programs proposed by CSPCo and OPCo as part of their ESP filings. The PUCO decided that those requests should be examined in the context of a complete distribution base rate case. The order did not require CSPCo and/or OPCo to file a distribution base rate case. |
· | The approval of CSPCo’s and OPCo’s request to recover the incremental carrying costs related to environmental investments made from 2001 through 2008 that are not reflected in existing rates. Future recovery during the ESP period of incremental carrying charges on environmental expenditures incurred beginning in 2009 may be requested in annual filings. |
· | The approval of a $97 million and $55 million increase in CSPCo’s and OPCo’s Provider of Last Resort charges, respectively, to compensate for the risk of customers changing electric suppliers during the ESP period. |
· | The requirement that CSPCo’s and OPCo’s shareholders fund a combined minimum of $15 million in costs over the ESP period for low-income, at-risk customer programs. This funding obligation was recognized as a liability and an unfavorable adjustment to Other Operation and Maintenance expense for the three-month period ending March 31, 2009. |
· | The deferral of CSPCo’s and OPCo’s request to recover certain existing regulatory assets, including customer choice implementation and line extension carrying costs as part of the ESPs. The PUCO decided it would be more appropriate to consider this request in the context of CSPCo’s and OPCo’s next distribution base rate case. These regulatory assets, which were approved by prior PUCO orders, total $58 million for CSPCo and $40 million for OPCo as of March 31, 2009. In addition, CSPCo and OPCo would recover and recognize as income, when collected, $35 million and $26 million, respectively, of related unrecorded equity carrying costs incurred through March 2009. |
Finally, consistent with its decisions on ESP orders of other companies, the PUCO ordered its staff to convene a workshop to determine the methodology for the SEET that will be applicable to all electric utilities in Ohio. The SEET requires the PUCO to determine, following the end of each year of the ESP, if any rate adjustments included in the ESP resulted in excessive earnings as measured by whether the earned return on common equity of CSPCo and OPCo is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that have comparable business and financial risk. If the rate adjustments, in the aggregate, result in significantly excessive earnings in comparison, the PUCO must require that the amount of the excess be returned to customers. The PUCO’s decision on the SEET review of CSPCo’s and OPCo’s 2009 earnings is not expected to be finalized until the second or third quarter of 2010.
In March 2009, intervenors filed a motion to stay a portion of the ESP rates or alternately make that portion subject to refund because the intervenors believed that the ordered ESP rates for 2009 were retroactive and therefore unlawful. In March 2009, the PUCO approved CSPCo’s and OPCo’s tariffs effective with the April 2009 billing cycle and rejected the intervenors’ motion. The PUCO also clarified that the reference in its earlier order to the January 1, 2009 date related to the term of the ESP, not to the effective date of tariffs and clarified the tariffs were not retroactive. In March 2009, CSPCo and OPCo implemented the new ESP tariffs effective with the start of the April 2009 billing cycle. In April 2009, CSPCo and OPCo filed a motion requesting rehearing of several issues. In April 2009, several intervenors filed motions requesting rehearing of issues underlying the PUCO’s authorized rate increases and one intervenor filed a motion requesting the PUCO to direct CSPCo and OPCo to cease collecting rates under the order. Certain intervenors also filed a complaint for writ of prohibition with the Ohio legislature passed Senate Bill 221, which amendsSupreme Court to halt any further collection from customers of what the restructuring law effective July 31, 2008 and requires electric utilities to adjust their rates by filing an Electric Security Plan (ESP). Electric utilitiesintervenors claim is unlawful retroactive rate increases.
Management will evaluate whether it will withdraw the ESP applications after a final order, thereby terminating the ESP proceedings. If CSPCo and/or OPCo withdraw the ESP applications, CSPCo and/or OPCo 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, fromor another ESP as permitted by the date of its commencement, could transition CSPColaw. The revenues collected and OPCo to full market rates no sooner than six years and no later than ten years after therecorded in 2009 under this 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 operationsorder are not subject to cost-based rate regulation accounting. However, if a fuel cost recovery mechanism is implemented withinpossible refund through the ESP, CSPCo’s and OPCo’s fuel and purchased power operations would be subject to cost-based rate regulation accounting.SEET process. 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 relateddue 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. Failuredecision of the PUCO to ultimately approvedefer guidance on the recoverySEET methodology to a future generic SEET proceeding, to estimate the amount, if any, of a possible refund that could result from the regulatory assets would have an adverse effect on future net income and cash flows.SEET process in 2010.
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 Cook Plant Unit 1 (Unit 1) due to turbine vibrations, likely caused by blade failure, which resulted in a fire on the electric generator. This equipment, islocated in the turbine building, and is separate and isolated from the nuclear reactor. The steam turbinesturbine rotors that caused the vibration were installed in 2006 and are underwithin the vendor’s warranty from the vendor.period. The warranty provides for the repair or replacement of the turbinesturbine rotors if the damage was caused by a defect in the designmaterials or assembly of the turbines.workmanship. I&M is also working with its insurance company, Nuclear Electric Insurance Limited (NEIL), and its turbine vendor, Siemens, to evaluate the extent of the damage resulting from the incident and the costsfacilitate repairs to return the unit to service. We cannot estimate the ultimate costsRepair of the outage at this time.property damage and replacement of the turbine rotors and other equipment could cost up to approximately $330 million. 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 thatThe treatment of property damage costs, replacement power costs and insurance proceeds will be the subject of future regulatory proceedings in Indiana and Michigan. I&M is repairing Unit 1 couldto resume operations as early as late first quarter/early second quarterOctober 2009 at reduced power. Should post-repair operations prove unsuccessful, the replacement of 2009 or as late asparts will extend the second half of 2009, depending upon whether the damaged components can be repaired or whether they need to be replaced.outage into 2011.
I&M maintains property insurance through NEIL with a $1 million deductible. As of March 31, 2009, we recorded $34 million in Prepayments and Other on our Condensed Consolidated Balance Sheets representing recoverable amounts under the property insurance policy. I&M received partial reimbursements from NEIL for the cost incurred to date to repair the property damage. I&M also maintains a separate accidental outage policy with NEIL whereby, after a 12 week12-week deductible period, I&M is entitled to weekly payments of $3.5 million duringfor the first 52 weeks following the deductible period. After the initial 52 weeks of indemnity, the policy pays $2.8 million per week for up to an additional 110 weeks. I&M began receiving payments under the accidental outage period for a covered loss.policy in December 2008. In the first quarter of 2009, I&M recorded $54 million in revenues, including $9 million in revenues that were deferred at December 31, 2008, related to the accidental outage policy. In order to hold customers harmless, in the first quarter of 2009, I&M applied $20 million of the accidental outage insurance proceeds to reduce fuel underrecoveries reflecting recoverable fuel costs as if Unit 1 were operating. 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 inthrough the end of 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 paidAlthough earnings were not affected by this CTC refund, cash flow was adversely impacted for these CTC refunds for the nine months ended September 30, 2008, 2007 and 2007 was2006 by $75 million, $238 million and $207$69 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. This remand could potentially have an adverse effect on TCC’s future net income and cash flows if upheld on appeal. The district courtDistrict Court judge also determined that the PUCT improperly reduced TCC’s net stranded plant costs for commercial unreasonableness.unreasonableness which could have a favorable effect on TCC’s future net income and cash flows.
TCC, the PUCT and intervenors appealed the district courtDistrict Court decision to the Texas Court of Appeals. In May 2008, the Texas Court of Appeals affirmed the district courtDistrict Court decision in all but onetwo major respect.respects. It reversed the district court’sDistrict Court’s unfavorable decision findingwhich found that the PUCT erred by applying an invalid rule to determine the carrying cost rate. It also determined that the PUCT erred by not reducing stranded costs by the “excess earnings” that had already been refunded to affiliated REPs. Management does not believe that TCC will be adversely affected by the Court of Appeals ruling on excess earnings based upon the reasons discussed in the “TCC Excess Earnings” section below. The favorable commercial unreasonableness decisionjudgment entered by the District Court 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. Review is discretionary and the Texas Supreme Court has not determined if it will grant review. In January 2009, the Texas Supreme Court requested full briefing of the proceedings.
TNC received its final true-up order in May 2005 that resulted in refunds via a CTC which have been completed. The appeal brought by TNC of the final true-up order remains pending in state court.
Management cannot predict the outcome of these court proceedings and PUCT remand decisions. If TCC and/or TNC ultimately succeedssucceed in itstheir 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 substantialmaterial adverse effect on future net income, cash flows and possibly financial condition.
New GenerationGeneration/Purchase Power Agreement
In 2008,2009, AEP completed or is in various stages of construction of the following generation facilities:
| | | | | | | | | | | | | | | | | Commercial |
| | | | | | Total | | | | | | | | | Nominal | | Operation |
Operating | | Project | | | | Projected | | | | | | | | | MW | | Date |
Company | | Name | | Location | | Cost (a) | | CWIP (b) | | Fuel Type | | Plant Type | | Capacity | | (Projected) |
| | | | | | (in millions) | | (in millions) | | | | | | | | |
PSO | | Southwestern | (c) | Oklahoma | | $ | 56 | | $ | - | | Gas | | Simple-cycle | | 150 | | 2008 | |
PSO | | Riverside | (d) | Oklahoma | | | 58 | | | - | | Gas | | Simple-cycle | | 150 | | 2008 | |
AEGCo | | Dresden | (e) | Ohio | | | 309 | (h) | | 149 | | Gas | | Combined-cycle | | 580 | | 2010 | (h) |
SWEPCo | | Stall | | Louisiana | | | 378 | | | 158 | | Gas | | Combined-cycle | | 500 | | 2010 | |
SWEPCo | | Turk | (f) | Arkansas | | | 1,522 | (f) | | 448 | | Coal | | Ultra-supercritical | | 600 | (f) | 2012 | |
APCo | | Mountaineer | (g) | West Virginia | | | | (g) | | | | Coal | | IGCC | | 629 | | (g) | |
CSPCo/OPCo | | Great Bend | (g) | Ohio | | | | (g) | | | | Coal | | IGCC | | 629 | | (g) | |
| | | | | | | | | | | | | | | | | Commercial |
| | | | | | Total | | | | | | | | | Nominal | | Operation |
Operating | | Project | | | | Projected | | | | | | | | | MW | | Date |
Company | | Name | | Location | | Cost (a) | | CWIP (b) | | Fuel Type | | Plant Type | | Capacity | | (Projected) |
| | | | | | (in millions) | | (in millions) | | | | | | | | |
AEGCo | | Dresden | (c) | Ohio | | $ | 322 | | $ | 189 | | Gas | | Combined-cycle | | 580 | | 2013 |
SWEPCo | | Stall | | Louisiana | | | 385 | | | 291 | | Gas | | Combined-cycle | | 500 | | 2010 |
SWEPCo | | Turk | (d) | Arkansas | | | 1,628 | (d) | | 480 | | Coal | | Ultra-supercritical | | 600 | (d) | 2012 |
APCo | | Mountaineer | (e) | West Virginia | | | | (e) | | | | Coal | | IGCC | | 629 | | (e) |
CSPCo/OPCo | | Great Bend | (e) | Ohio | | | | (e) | | | | Coal | | IGCC | | 629 | | (e) |
(a) | Amount excludes AFUDC. |
(b) | Amount includes AFUDC. |
(c) | Southwestern Units were placed in service on February 29, 2008. |
(d) | The final Riverside Unit was placed in service on June 15, 2008. |
(e) | In September 2007, AEGCo purchased the partially completed Dresden Plantplant from Dresden Energy LLC, a subsidiary of Dominion Resources, Inc., for $85 million, which is included in the “Total Projected Cost” section above. |
(f)(d) | SWEPCo plans to own approximately 73%, or 440 MW, totaling $1.1$1.2 billion in capital investment. The increase in the cost estimate disclosed in the 2007 Annual Report relates to cost escalations due to the delay in receipt of permits and approvals. See “Turk Plant” section below. |
(g)(e) | Construction of IGCC plants are pending necessary permits andis subject to regulatory approval.approvals. See “IGCC Plants” section below. |
(h) | Projected completion date of the Dresden Plant is currently under review. To the extent that the completion date is delayed, the total projected cost of the Dresden Plant could change. |
Turk Plant
In November 2007, the APSC granted approval to build the Turk Plant. Certain landowners filed a notice of appealhave appealed the APSC’s decision 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 $1.5previously estimated $1.522 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 emissionsemission costs exceed the restrictions, it could have a material adverse impacteffect 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.landowners. 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 2009, SWEPCo filed a motion to dismiss the appeal. In March 2009, the motion was granted.
In November 2008, SWEPCo received the required air permit approval from the Arkansas Department of Environmental Quality and commenced construction. In December 2008, Arkansas landowners filed an appeal with the Arkansas Pollution Control and Ecology Commission (APCEC) which caused construction of the Turk Plant to halt until the APCEC took further action. In December 2008, SWEPCo filed a request with the APCEC to continue construction of the Turk Plant and the APCEC ruled to allow construction to continue while an appeal of the Turk Plant’s permit is heard. Hearings on the air permit appeal are scheduled for June 2009. SWEPCo is also working with the U.S. Army Corps of Engineers for the approval of a wetlands and stream impact permit. In March 2009, SWEPCo reported to the U.S. Army Corps of Engineers a potential wetlands impact on approximately 2.5 acres at the Turk Plant. The U.S. Army Corps of Engineers directed SWEPCo to cease further work impacting the wetland areas. Construction has continued on other areas of the Turk Plant. The impact on the construction schedule and workforce is currently being evaluated by management.
In January 2008 and July 2008, SWEPCo filed Certificate of Environmental Compatibility and Public Need (CECPN) 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. TheIn June 2008, the landowner filed an appeal to the Arkansas State Court of Appeals in June 2008.requesting to re-litigate Turk Plant issues. SWEPCo responded and the appeal was dismissed. In January 2009, the APSC approved the CECPN applications.
The Arkansas Governor’s Commission on Global Warming is scheduled to issueissued its final report to the Governor by November 1,governor in October 2008. The Commission was established to set a global warming pollution reduction goal together with a strategic plan for implementation in Arkansas. The Commission’s final report included a recommendation that the Turk Plant employ post combustion carbon capture and storage measures as soon as it starts operating. If legislation is passed as a result of the findings in the Commission’s report, it could impact SWEPCo’s proposal to build and operate 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 paidcosts incurred plus related shutdown 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,March 31, 2009, SWEPCo has capitalized approximately $448$480 million of expenditures (including AFUDC) and has significant contractual construction commitments for an additional $771$655 million. As of September 30, 2008,March 31, 2009, if the plant had been cancelled, SWEPCo would have incurred cancellation fees of $61 million would have been required in order to terminate these construction commitments.$100 million. 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 MayApril 2008, the Virginia SCC denied APCo’s request to reconsider the Virginia SCC’s previous denial ofissued an order denying 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. Comments were filed by various parties, including APCo, but the WVPSC has not taken any action. 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,March 2009, APCo deferred for future recovery preconstruction IGCC costs of $19$20 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, neither CSPCo nor OPCo are engaged in a continuous course of construction on the IGCC plant. However, 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 1pre-construction 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.
PSO Purchase Power Agreement
PSO and Exelon Generation Company LLC, a subsidiary of Exelon Corporation, executed a long-term purchase power agreement (PPA) for which an application seeking its approval is expected to be filed with the OCC. The PPA is for the purchase of up to 520 MW of electric generation from the 795 MW natural gas-fired Green Country Generating Station, located in Jenks, Oklahoma. The agreement is the result of PSO’s 2008 Request for Proposals following a December 2007 OCC order that found PSO had a need for new baseload generation by 2012.
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, assessassesses the probability of loss for such contingencieseach contingency 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 20072008 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.income and cash flows.
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 underLitigation continues against Beckjord, a consent decree.plant jointly-owned by CSPCo, jointly-owns Beckjord and Stuart Stations with Duke and DP&L.&L, which Duke operates. A jury trial in May 2008 returned a verdict of no liability at the jointly-owned Beckjord unit. In OctoberDecember 2008, however, the court approvedordered a settlementnew trial in the citizen suit action filed by Sierra Club againstBeckjord case. We are unable to predict the jointly-owned units at Stuart Station. Under the settlement, the joint-ownersoutcome of Stuart Station agreedthis case. We believe we can recover any capital and operating costs of additional pollution control equipment that may be required through future regulated rates or market prices for electricity. If we are unable to certain emission targets related to NOx, SO2recover such costs or if material penalties are imposed, it would adversely affect future net income 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.cash flows.
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:
· | Requirements under CAA to reduce emissions of SO2, NOx, PMparticulate matter (PM) and mercury from fossil fuel-fired power plants; and |
· | Requirements under the Clean Water Act (CWA) to reduce the impacts of water intake structures on aquatic species at certain of our power plants. |
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 engagedinvolved in the development of possible future requirements to reduce CO2 and other greenhouse gasgases (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 20072008 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 2008,2009, the U.S. Supreme Court agreed to review decisions from the Second Circuit Court of Appealsissued a decision that limitallows the Federal EPA’s abilityEPA the discretion to weighrely on cost-benefit analysis in setting national performance standards and in providing for cost-benefit variances from those standards as part of the retrofittingregulations. We cannot predict if or how the Federal EPA will apply this decision to any revision of the regulations or what effect it may have on similar requirements adopted by the states.
Potential Regulation of CO2 and Other GHG Emissions
As discussed in the 2008 Annual Report, CO2 and other GHG are alleged to contribute to climate change. In April 2009, the Federal EPA issued a proposed endangerment finding under the CAA regarding GHG emissions from motor vehicles. The proposed endangerment finding is subject to public comment. This finding could lead to regulation of CO2 and other gases under existing laws. Congress continues to discuss new legislation related to the control of these emissions. Some policy approaches being discussed would have significant and widespread negative consequences for the national economy and major U.S. industrial enterprises, including us. Because of these adverse consequences, management believes that these more extreme policies will not ultimately be adopted. Even if reasonable CO2 and other GHG emission standards are imposed, they will still require us to make material expenditures. Management believes that costs against environmental benefits. Management is unable to predict the outcome of this appeal.complying with new CO2 and other GHG emission standards will be treated like all other reasonable costs of serving customers, and should be recoverable from customers as costs of doing business including capital investments with a return on investment.
Critical Accounting Estimates
See the “Critical Accounting Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 20072008 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, theThe FASB issued SFAS 157 “Fair Value Measurements”141R (revised “Business Combinations” 2007) improving financial reporting about business combinations and their effects. SFAS 141R can affect tax positions on previous acquisitions. We do not have any such tax positions that result in adjustments. We adopted SFAS 141R effective January 1, 2009. We will apply it to any future business combinations.
The FASB issued SFAS 160 “Noncontrolling Interest in Consolidated Financial Statements” (SFAS 157)160), modifying reporting for noncontrolling interest (minority interest) in consolidated financial statements. The statement requires noncontrolling interest be reported in equity and establishes a new framework for recognizing net income or loss and comprehensive income by the controlling interest. We adopted SFAS 160 effective January 1, 2009 and retrospectively applied the standard to prior periods. See Note 2.
The FASB issued SFAS 161 “Disclosures about Derivative Instruments and Hedging Activities” (SFAS 161), enhancing existing guidancedisclosure requirements for fair value measurement of assetsderivative instruments 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.hedging activities. The standard requires fair value measurementsthat objectives for using derivative instruments be disclosed by hierarchy level, an entity includes its own credit standing in the measurementterms of its liabilitiesunderlying risk and modifies the transaction price presumption. accounting designation. This standard increased our disclosure requirements related to derivative instruments and hedging activities. We adopted SFAS 161 effective January 1, 2009.
The standard also nullifies the consensus reached inFASB ratified EITF Issue No. 02-3 “Issues Involved in08-5 “Issuer’s Accounting for Derivative Contracts Held for Trading PurposesLiabilities Measured at Fair Value with a Third-Party Credit Enhancement” (EITF 08-5) a consensus on liabilities with third-party credit enhancements when the liability is measured and Contracts Involveddisclosed at fair value. The consensus treats the liability and the credit enhancement as two units of accounting. We adopted EITF 08-5 effective January 1, 2009. It will be applied prospectively with the effect of initial application included as a change 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 liability.
The FASB ratified EITF Issue No. 08-6 “Equity Method Investment Accounting Considerations” (EITF 08-6), a consensus on equity method investment accounting including initial and allocated carrying values and subsequent measurements. We prospectively adopted EITF 08-6 effective January 1, 2009 with no impact on our financial statements.
We adopted FSP EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (EITF 03-6-1) effective January 1, 2009. The rule addressed whether instruments granted in share-based payment transactions are participating securities prior to vesting and determined that the instruments need to be included in earnings allocation in computing EPS under the two-class method. The adoption of this standard had an immaterial impact on our financial statements.
The FASB issued FSP SFAS 157-1 “Application142-3 “Determination of FASB Statement No. 157the Useful Life of Intangible Assets” amending factors that should be considered in developing renewal or extension assumptions used to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposesdetermine the useful life of Lease Classification or Measurement under Statement 13” which amends SFAS 157a recognized intangible asset. We adopted the rule effective January 1, 2009. The guidance is prospectively applied to exclude SFAS 13 “Accounting for Leases” and other accounting pronouncements that address fair value measurements for purposesintangible assets acquired after the effective date. The standard’s disclosure requirements are applied prospectively to all intangible assets as of lease classification or measurement under SFAS 13. In February 2008, theJanuary 1, 2009. The adoption of this standard had no impact on our financial statements.
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 ofAs defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets that are notfor identical assets or liabilities and the lowest priority to unobservable inputs. In the absence of quoted prices for identical or similar assets or investments in active markets, fair value is estimated using various internal and provides an illustrative example. The provisions ofexternal valuation methods including cash flow analysis and appraisals. We adopted SFAS 157 are applied prospectively, except for a) changes in157-2 effective January 1, 2009. We will apply these requirements to applicable 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 pricewhich include new asset retirement obligations and c) blockage discount factors. Although the statement is applied prospectively upon adoption, in accordance with the provisions of SFAS 157impairment analysis 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 onlong-lived assets, equity investments, goodwill and intangibles. We did not record any 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 totalnonrecurring nonfinancial assets and liabilities onin the December 31, 2007 balance sheet by $47 million each. See “FSP FIN 39-1 “Amendmentfirst quarter of FASB Interpretation No. 39” (FIN 39-1)” section of Note 2.2009.
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 liquidatesettle 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, coal, natural gas coal and emissionsemission allowances 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 Sheetbalance sheet as of September 30, 2008March 31, 2009 and the reasons for changes in our total MTM value included on our Condensed Consolidated Balance Sheetbalance sheet as compared to December 31, 2007.2008.
Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
September 30, 2008March 31, 2009
(in millions)
| | Utility Operations | | | Generation and Marketing | | | All Other | | | Sub-Total MTM Risk Management Contracts | | | MTM of Cash Flow and Fair Value Hedges | | | Collateral Deposits | | | Total | |
Current Assets | | $ | 246 | | | $ | 52 | | | $ | 43 | | | $ | 341 | | | $ | 25 | | | $ | (26 | ) | | $ | 340 | |
Noncurrent Assets | | | 164 | | | | 128 | | | | 40 | | | | 332 | | | | 6 | | | | (24 | ) | | | 314 | |
Total Assets | | | 410 | | | | 180 | | | | 83 | | | | 673 | | | | 31 | | | | (50 | ) | | | 654 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current Liabilities | | | (209 | ) | | | (65 | ) | | | (47 | ) | | | (321 | ) | | | (18 | ) | | | 9 | | | | (330 | ) |
Noncurrent Liabilities | | | (69 | ) | | | (57 | ) | | | (43 | ) | | | (169 | ) | | | (4 | ) | | | 8 | | | | (165 | ) |
Total Liabilities | | | (278 | ) | | | (122 | ) | | | (90 | ) | | | (490 | ) | | | (22 | ) | | | 17 | | | | (495 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 132 | | | $ | 58 | | | $ | (7 | ) | | $ | 183 | | | $ | 9 | | | $ | (33 | ) | | $ | 159 | |
| | Utility Operations | | | Generation and Marketing | | | All Other | | | Sub-Total MTM Risk Management Contracts | | | Cash Flow Hedge Contracts | | | Collateral Deposits | | | Total | |
Current Assets | | $ | 256 | | | $ | 27 | | | $ | 4 | | | $ | 287 | | | $ | 40 | | | $ | (34 | ) | | $ | 293 | |
Noncurrent Assets | | | 228 | | | | 221 | | | | 7 | | | | 456 | | | | 1 | | | | (40 | ) | | | 417 | |
Total Assets | | | 484 | | | | 248 | | | | 11 | | | | 743 | | | | 41 | | | | (74 | ) | | | 710 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current Liabilities | | | (153 | ) | | | (23 | ) | | | (9 | ) | | | (185 | ) | | | (31 | ) | | | 37 | | | | (179 | ) |
Noncurrent Liabilities | | | (155 | ) | | | (85 | ) | | | (10 | ) | | | (250 | ) | | | (4 | ) | | | 80 | | | | (174 | ) |
Total Liabilities | | | (308 | ) | | | (108 | ) | | | (19 | ) | | | (435 | ) | | | (35 | ) | | | 117 | | | | (353 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 176 | | | $ | 140 | | | $ | (8 | ) | | $ | 308 | | | $ | 6 | | | $ | 43 | | | $ | 357 | |
MTM Risk Management Contract Net Assets (Liabilities)
NineThree Months Ended September 30, 2008March 31, 2009
(in millions)
| | Utility Operations | | | Generation and Marketing | | | All Other | | | Total | |
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2007 | | $ | 156 | | | $ | 43 | | | $ | (8 | ) | | $ | 191 | |
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | | | (57 | ) | | | 4 | | | | 1 | | | | (52 | ) |
Fair Value of New Contracts at Inception When Entered During the Period (a) | | | 2 | | | | 17 | | | | - | | | | 19 | |
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b) | | | 3 | | | | 3 | | | | 1 | | | | 7 | |
Changes in Fair Value Due to Market Fluctuations During the Period (c) | | | 18 | | | | (9 | ) | | | (1 | ) | | | 8 | |
Changes in Fair Value Allocated to Regulated Jurisdictions (d) | | | 10 | | | | - | | | | - | | | | 10 | |
Total MTM Risk Management Contract Net Assets (Liabilities) at September 30, 2008 | | $ | 132 | | | $ | 58 | | | $ | (7 | ) | | | 183 | |
Net Cash Flow and Fair Value Hedge Contracts | | | | | | | | | | | | | | | 9 | |
Collateral Deposits | | | | | | | | | | | | | | | (33 | ) |
Ending Net Risk Management Assets at September 30, 2008 | | | | | | | | | | | | | | $ | 159 | |
| | Utility Operations | | | Generation and Marketing | | | All Other | | | Total | |
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2008 | | $ | 175 | | | $ | 104 | | | $ | (7 | ) | | $ | 272 | |
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | | | (27 | ) | | | (3 | ) | | | 1 | | | | (29 | ) |
Fair Value of New Contracts at Inception When Entered During the Period (a) | | | 2 | | | | 51 | | | | - | | | | 53 | |
Net Option Premiums Paid (Received) for Unexercised or Unexpired Option Contracts Entered During the Period | | | - | | | | - | | | | - | | | | - | |
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts | | | - | | | | - | | | | - | | | | - | |
Changes in Fair Value Due to Market Fluctuations During the Period (b) | | | 7 | | | | (12 | ) | | | (2 | ) | | | (7 | ) |
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | | | 19 | | | | - | | | | - | | | | 19 | |
Total MTM Risk Management Contract Net Assets (Liabilities) at March 31, 2009 | | $ | 176 | | | $ | 140 | | | $ | (8 | ) | | | 308 | |
Cash Flow Hedge Contracts | | | | | | | | | | | | | | | 6 | |
Collateral Deposits | | | | | | | | | | | | | | | 43 | |
Ending Net Risk Management Assets at March 31, 2009 | | | | | | | | | | | | | | $ | 357 | |
(a) | Reflects fair value on long-term structured contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged. |
(b) | Represents the impact of applying AEP’s credit risk when measuring the fair value of derivative liabilities according to SFAS 157. |
(c) | Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc. |
(d)(c) | “Change in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected on the Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities.liabilities/assets. |
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets (Liabilities)
The following table presents the maturity, by year, of our net assets/liabilities, to give an indication of when these MTM amounts will settle and generate cash:
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets (Liabilities)
Fair Value of Contracts as of September 30, 2008March 31, 2009
(in millions)
| | Remainder 2008 | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | After 2012 (f) | | | Total | |
Utility Operations: | | | | | | | | | | | | | | | | | | | | | |
Level 1 (a) | | $ | (2 | ) | | $ | (8 | ) | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | (10 | ) |
Level 2 (b) | | | 5 | | | | 62 | | | | 43 | | | | 5 | | | | 1 | | | | - | | | | 116 | |
Level 3 (c) | | | (15 | ) | | | 2 | | | | (6 | ) | | | 1 | | | | 1 | | | | - | | | | (17 | ) |
Total | | | (12 | ) | | | 56 | | | | 37 | | | | 6 | | | | 2 | | | | - | | | | 89 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Generation and Marketing: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Level 1 (a) | | | (1 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (1 | ) |
Level 2 (b) | | | (21 | ) | | | 2 | | | | 11 | | | | 12 | | | | 11 | | | | 20 | | | | 35 | |
Level 3 (c) | | | 5 | | | | 2 | | | | 3 | | | | 2 | | | | 2 | | | | 10 | | | | 24 | |
Total | | | (17 | ) | | | 4 | | | | 14 | | | | 14 | | | | 13 | | | | 30 | | | | 58 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
All Other: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Level 1 (a) | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
Level 2 (b) | | | (1 | ) | | | (4 | ) | | | (4 | ) | | | 2 | | | | - | | | | - | | | | (7 | ) |
Level 3 (c) | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
Total | | | (1 | ) | | | (4 | ) | | | (4 | ) | | | 2 | | | | - | | | | - | | | | (7 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Level 1 (a) | | | (3 | ) | | | (8 | ) | | | - | | | | - | | | | - | | | | - | | | | (11 | ) |
Level 2 (b) | | | (17 | ) | | | 60 | | | | 50 | | | | 19 | | | | 12 | | | | 20 | | | | 144 | |
Level 3 (c) (d) | | | (10 | ) | | | 4 | | | | (3 | ) | | | 3 | | | | 3 | | | | 10 | | | | 7 | |
Total | | | (30 | ) | | | 56 | | | | 47 | | | | 22 | | | | 15 | | | | 30 | | | | 140 | |
Dedesignated Risk Management Contracts (e) | | | 4 | | | | 14 | | | | 14 | | | | 6 | | | | 5 | | | | - | | | | 43 | |
Total MTM Risk Management Contract Net Assets (Liabilities) | | $ | (26 | ) | | $ | 70 | | | $ | 61 | | | $ | 28 | | | $ | 20 | | | $ | 30 | | | $ | 183 | |
| | Remainder 2009 | | | 2010 | | | 2011 | | | 2012 | | | 2013 | | | After 2013 (f) | | | Total | |
Utility Operations | | | | | | | | | | | | | | | | | | | | | |
Level 1 (a) | | $ | (6 | ) | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | (6 | ) |
Level 2 (b) | | | 62 | | | | 34 | | | | 17 | | | | (1 | ) | | | - | | | | - | | | | 112 | |
Level 3 (c) | | | 16 | | | | 8 | | | | 5 | | | | 5 | | | | 1 | | | | - | | | | 35 | |
Total | | | 72 | | | | 42 | | | | 22 | | | | 4 | | | | 1 | | | | - | | | | 141 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Generation and Marketing | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Level 1 (a) | | | (8 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (8 | ) |
Level 2 (b) | | | 7 | | | | 15 | | | | 16 | | | | 16 | | | | 18 | | | | 25 | | | | 97 | |
Level 3 (c) | | | 1 | | | | 1 | | | | 2 | | | | 1 | | | | 3 | | | | 43 | | | | 51 | |
Total | | | - | | | | 16 | | | | 18 | | | | 17 | | | | 21 | | | | 68 | | | | 140 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
All Other | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Level 1 (a) | | | - | | | | (1 | ) | | | - | | | | - | | | | - | | | | - | | | | (1 | ) |
Level 2 (b) | | | (4 | ) | | | (5 | ) | | | 2 | | | | - | | | | - | | | | - | | | | (7 | ) |
Level 3 (c) | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
Total | | | (4 | ) | | | (6 | ) | | | 2 | | | | - | | | | - | | | | - | | | | (8 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Level 1 (a) | | | (14 | ) | | | (1 | ) | | | - | | | | - | | | | - | | | | - | | | | (15 | ) |
Level 2 (b) | | | 65 | | | | 44 | | | | 35 | | | | 15 | | | | 18 | | | | 25 | | | | 202 | |
Level 3 (c) (d) | | | 17 | | | | 9 | | | | 7 | | | | 6 | | | | 4 | | | | 43 | | | | 86 | |
Total | | | 68 | | | | 52 | | | | 42 | | | | 21 | | | | 22 | | | | 68 | | | | 273 | |
Dedesignated Risk Management Contracts (e) | | | 10 | | | | 14 | | | | 6 | | | | 5 | | | | - | | | | - | | | | 35 | |
Total MTM Risk Management Contract Net Assets (Liabilities) | | $ | 78 | | | $ | 66 | | | $ | 48 | | | $ | 26 | | | $ | 22 | | | $ | 68 | | | $ | 308 | |
(a) | Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis. |
(b) | Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1 and OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market. |
(c) | Level 3 inputs are unobservable inputs for the asset or liability. Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions. |
(d) | A significant portion of the total volumetric position within the consolidated levelLevel 3 balance has been economically hedged. |
(e) | Dedesignated Risk Management Contracts are contracts that were originally MTM but were subsequently elected as normal under SFAS 133. At the time of the normal election, the MTM value was frozen and no longer fair valued. This will be amortized within Utility Operations Revenues over the remaining life of the contract.contracts. |
(f) | There is mark-to-market value of $30$68 million in individual periods beyond 2012. $142014. $46 million of this mark-to-market value is in 2013, $8periods 2014-2018, $15 million is in 2014, $3periods 2019-2023 and $7 million is in 2015, $2 million is in 2016 and $3 million is in 2017.periods 2024-2028. |
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed Consolidated Balance Sheets
We are exposed to market fluctuations in energy commodity prices impacting our power operations. We monitor these risks on our future operations and may use various commodity derivative instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows. We do not hedge all commodity price risk.
We use interest rate derivative transactions to manage interest rate risk related to existing variable rate debt and to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate exposure.
We use foreign currency derivatives to lock in prices on certain forecasted transactions denominated in foreign currencies where deemed necessary, and designate qualifying instruments as cash flow hedges. We do not hedge all foreign currency exposure.
The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for changes in cash flow hedges from December 31, 2007 to September 30, 2008. The following table also indicates what portion of designated, effective hedges are expected to be reclassified into net income in the next 12 months. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts which are not designated as effective cash flow hedges are marked-to-market and are included in the previous risk management tables.
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges
Nine Months Ended September 30, 2008
(in millions)
| | Power | | | Interest Rate and Foreign Currency | | | Total | |
Beginning Balance in AOCI, December 31, 2007 | | $ | (1 | ) | | $ | (25 | ) | | $ | (26 | ) |
Changes in Fair Value | | | 7 | | | | (5 | ) | | | 2 | |
Reclassifications from AOCI for Cash Flow Hedges Settled | | | 2 | | | | 3 | | | | 5 | |
Ending Balance in AOCI, September 30, 2008 | | $ | 8 | | | $ | (27 | ) | | $ | (19 | ) |
| | | | | | | | | | | | |
After Tax Portion Expected to be Reclassified to Earnings During Next 12 Months | | $ | 6 | | | $ | (5 | ) | | $ | 1 | |
Credit Risk
We limit credit risk in our wholesale marketing and trading activities by assessing creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness after transactions have been initiated. We use Moody’s Investors Service, Standard & Poor’s and qualitative and quantitative data to assess the financial health of counterparties on an ongoing basis. If an external rating is not available, an internal rating is generated utilizing a quantitative tool developed by Moody’s to estimate probability of default that corresponds to an implied external agency credit rating. Based on our analysis, we set appropriate risk parameters for each internally-graded counterparty. We may also require cash deposits, letters of credit and parental/affiliate guarantees as security from counterparties in order to mitigate credit risk.
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. At September 30, 2008,March 31, 2009, our credit exposure net of collateral to sub investment grade counterparties was approximately 14.5%10.6%, expressed in terms of net MTM assets, net receivables and the net open positions for contracts not subject to MTM (representing economic risk even though there may not be risk of accounting loss). The increase from 5.4% at December 31, 2007 is primarily related to an increase in exposure with coal counterparties. Approximately 57% of our credit exposure net of collateral to sub investment grade counterparties is short-term exposure of less than one year. As of September 30, 2008,March 31, 2009, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable (in millions, except number of counterparties):applicable:
Counterparty Credit Quality | | Exposure Before Credit Collateral | | | Credit Collateral | | | Net Exposure | | | Number of Counterparties >10% of Net Exposure | | | Net Exposure of Counterparties >10% | |
Investment Grade | | $ | 626 | | | $ | 42 | | | $ | 584 | | | | 2 | | | $ | 146 | |
Split Rating | | | 14 | | | | - | | | | 14 | | | | 2 | | | | 14 | |
Noninvestment Grade | | | 81 | | | | 8 | | | | 73 | | | | 2 | | | | 66 | |
No External Ratings: | | | | | | | | | | | | | | | | | | | | |
Internal Investment Grade | | | 110 | | | | - | | | | 110 | | | | 2 | | | | 77 | |
Internal Noninvestment Grade | | | 46 | | | | - | | | | 46 | | | | 2 | | | | 40 | |
Total as of September 30, 2008 | | $ | 877 | | | $ | 50 | | | $ | 827 | | | | 10 | | | $ | 343 | |
| | | | | | | | | | | | | | | | | | | | |
Total as of December 31, 2007 | | $ | 673 | | | $ | 42 | | | $ | 631 | | | | 6 | | | $ | 74 | |
| | Exposure Before Credit Collateral | | | Credit Collateral | | | Net Exposure | | | Number of Counterparties >10% of Net Exposure | | | Net Exposure of Counterparties >10% | |
Counterparty Credit Quality | | (in millions, except number of counterparties) | |
Investment Grade | | $ | 670 | | | $ | 89 | | | $ | 581 | | | | 1 | | | $ | 133 | |
Split Rating | | | 8 | | | | 1 | | | | 7 | | | | 2 | | | | 7 | |
Noninvestment Grade | | | 14 | | | | - | | | | 14 | | | | 1 | | | | 13 | |
No External Ratings: | | | | | | | | | | | | | | | | | | | | |
Internal Investment Grade | | | 166 | | | | 16 | | | | 150 | | | | 4 | | | | 87 | |
Internal Noninvestment Grade | | | 83 | | | | 10 | | | | 73 | | | | 2 | | | | 55 | |
Total as of March 31, 2009 | | $ | 941 | | | $ | 116 | | | $ | 825 | | | | 10 | | | $ | 295 | |
| | | | | | | | | | | | | | | | | | | | |
Total as of December 31, 2008 | | $ | 793 | | | $ | 29 | | | $ | 764 | | | | 9 | | | $ | 284 | |
See Note 7 for further information regarding MTM risk management contracts, cash flow hedging, accumulated other comprehensive income, credit risk and collateral triggering events.
VaR Associated with Risk Management Contracts
We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at September 30, 2008,March 31, 2009 a near term typical change in commodity prices is not expected to have a material effect on our net income, cash flows or financial condition.
The following table shows the end, high, average and low market risk as measured by VaR for the periods indicated:
VaR Model
Nine Months Ended September 30, 2008 | | Twelve Months Ended December 31, 2007 |
(in millions) | | (in millions) |
End | | High | | Average | | Low | | End | | High | | Average | | Low |
$2 | | $3 | | $1 | | $1 | | $1 | | $6 | | $2 | | $1 |
Three Months Ended | | | | | Twelve Months Ended |
March 31, 2009 | | | | | December 31, 2008 |
(in millions) | | | | | (in millions) |
End | | High | | Average | | Low | | | | | End | | High | | Average | | Low |
$1 | | $1 | | $1 | | $- | | | | | $- | | $3 | | $1 | | $- |
We back-test our VaR results against performance due to actual price moves. Based on the assumed 95% confidence interval, the performance due to actual price moves would be expected to exceed the VaR at least once every 20 trading days. Our backtesting results show that our actual performance exceeded VaR far fewer than once every 20 trading days. As a result, we believe our VaR calculation is conservative.
As our VaR calculation captures recent price moves, we also perform regular stress testing of the portfolio to understand our exposure to extreme price moves. We employ a historically-basedhistorical-based method whereby the current portfolio is subjected to actual, observed price moves from the last three years in order to ascertain which historical price moves translatestranslated into the largest potential mark-to-marketMTM loss. We then research the underlying positions, price moves and market events that created the most significant exposure.
Interest Rate Risk
We utilize an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which AEP’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months. The estimated EaR on our debt portfolio was $51$19 million. This amount includes the estimated impact of the April 2009 issuance of AEP common stock.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30,March 31, 2009 and 2008 and 2007
(in (in millions, except per-share amounts and shares outstanding)share amounts)
(Unaudited)
| | Three Months Ended | | | Nine Months Ended | |
| | 2008 | | | 2007 | | | 2008 | | | 2007 | |
REVENUES | | | | | | | | | | | | |
Utility Operations | | $ | 4,108 | | | $ | 3,423 | | | $ | 10,318 | | | $ | 9,127 | |
Other | | | 83 | | | | 366 | | | | 886 | | | | 977 | |
TOTAL | | | 4,191 | | | | 3,789 | | | | 11,204 | | | | 10,104 | |
| | | | | | | | | | | | | | | | |
EXPENSES | | | | | | | | | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 1,480 | | | | 1,099 | | | | 3,513 | | | | 2,853 | |
Purchased Electricity for Resale | | | 394 | | | | 358 | | | | 1,023 | | | | 895 | |
Other Operation and Maintenance | | | 1,010 | | | | 964 | | | | 2,870 | | | | 2,783 | |
Gain on Disposition of Assets, Net | | | (6 | ) | | | (2 | ) | | | (14 | ) | | | (28 | ) |
Asset Impairments and Other Related Charges | | | - | | | | - | | | | (255 | ) | | | - | |
Depreciation and Amortization | | | 387 | | | | 381 | | | | 1,123 | | | | 1,144 | |
Taxes Other Than Income Taxes | | | 189 | | | | 191 | | | | 578 | | | | 565 | |
TOTAL | | | 3,454 | | | | 2,991 | | | | 8,838 | | | | 8,212 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 737 | | | | 798 | | | | 2,366 | | | | 1,892 | |
| | | | | | | | | | | | | | | | |
Other Income: | | | | | | | | | | | | | | | | |
Interest and Investment Income | | | 14 | | | | 8 | | | | 45 | | | | 39 | |
Carrying Costs Income | | | 21 | | | | 14 | | | | 64 | | | | 38 | |
Allowance For Equity Funds Used During Construction | | | 11 | | | | 9 | | | | 32 | | | | 23 | |
| | | | | | | | | | | | | | | | |
INTEREST AND OTHER CHARGES | | | | | | | | | | | | | | | | |
Interest Expense | | | 216 | | | | 216 | | | | 670 | | | | 615 | |
Preferred Stock Dividend Requirements of Subsidiaries | | | 1 | | | | 1 | | | | 2 | | | | 2 | |
TOTAL | | | 217 | | | | 217 | | | | 672 | | | | 617 | |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE, MINORITY INTEREST EXPENSE AND EQUITY EARNINGS | | | 566 | | | | 612 | | | | 1,835 | | | | 1,375 | |
| | | | | | | | | | | | | | | | |
Income Tax Expense | | | 192 | | | | 205 | | | | 608 | | | | 443 | |
Minority Interest Expense | | | 1 | | | | 1 | | | | 3 | | | | 3 | |
Equity Earnings of Unconsolidated Subsidiaries | | | 1 | | | | 1 | | | | 3 | | | | 6 | |
| | | | | | | | | | | | | | | | |
INCOME BEFORE DISCONTINUED OPERATIONS AND EXTRAORDINARY LOSS | | | 374 | | | | 407 | | | | 1,227 | | | | 935 | |
| | | | | | | | | | | | | | | | |
DISCONTINUED OPERATIONS, NET OF TAX | | | - | | | | - | | | | 1 | | | | 2 | |
| | | | | | | | | | | | | | | | |
INCOME BEFORE EXTRAORDINARY LOSS | | | 374 | | | | 407 | | | | 1,228 | | | | 937 | |
| | | | | | | | | | | | | | | | |
EXTRAORDINARY LOSS, NET OF TAX | | | - | | | | - | | | | - | | | | (79 | ) |
| | | | | | | | | | | | | | | | |
NET INCOME | | $ | 374 | | | $ | 407 | | | $ | 1,228 | | | $ | 858 | |
| | | | | | | | | | | | | | | | |
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING | | | 402,286,779 | | | | 399,222,569 | | | | 401,535,661 | | | | 398,412,473 | |
| | | | | | | | | | | | | | | | |
BASIC EARNINGS PER SHARE | | | | | | | | | | | | | | | | |
Income Before Discontinued Operations and Extraordinary Loss | | $ | 0.93 | | | $ | 1.02 | | | $ | 3.06 | | | $ | 2.35 | |
Discontinued Operations, Net of Tax | | | - | | | | - | | | | - | | | | - | |
Income Before Extraordinary Loss | | | 0.93 | | | | 1.02 | | | | 3.06 | | | | 2.35 | |
Extraordinary Loss, Net of Tax | | | - | | | | - | | | | - | | | | (0.20 | ) |
TOTAL BASIC EARNINGS PER SHARE | | $ | 0.93 | | | $ | 1.02 | | | $ | 3.06 | | | $ | 2.15 | |
| | | | | | | | | | | | | | | | |
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING | | | 403,910,309 | | | | 400,215,911 | | | | 402,925,534 | | | | 399,552,630 | |
| | | | | | | | | | | | | | | | |
DILUTED EARNINGS PER SHARE | | | | | | | | | | | | | | | | |
Income Before Discontinued Operations and Extraordinary Loss | | $ | 0.93 | | | $ | 1.02 | | | $ | 3.05 | | | $ | 2.34 | |
Discontinued Operations, Net of Tax | | | - | | | | - | | | | - | | | | 0.01 | |
Income Before Extraordinary Loss | | | 0.93 | | | | 1.02 | | | | 3.05 | | | | 2.35 | |
Extraordinary Loss, Net of Tax | | | - | | | | - | | | | - | | | | (0.20 | ) |
TOTAL DILUTED EARNINGS PER SHARE | | $ | 0.93 | | | $ | 1.02 | | | $ | 3.05 | | | $ | 2.15 | |
| | | | | | | | | | | | | | | | |
CASH DIVIDENDS PAID PER SHARE | | $ | 0.41 | | | $ | 0.39 | | | $ | 1.23 | | | $ | 1.17 | |
REVENUES | | 2009 | | | 2008 | |
Utility Operations | | $ | 3,267 | | | $ | 3,010 | |
Other | | | 191 | | | | 457 | |
TOTAL | | | 3,458 | | | | 3,467 | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 929 | | | | 980 | |
Purchased Electricity for Resale | | | 295 | | | | 263 | |
Other Operation and Maintenance | | | 914 | | | | 878 | |
Gain on Disposition of Assets, Net | | | (9 | ) | | | (3 | ) |
Asset Impairments and Other Related Charges | | | - | | | | (255 | ) |
Depreciation and Amortization | | | 382 | | | | 363 | |
Taxes Other Than Income Taxes | | | 197 | | | | 198 | |
TOTAL | | | 2,708 | | | | 2,424 | |
| | | | | | | | |
OPERATING INCOME | | | 750 | | | | 1,043 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest and Investment Income | | | 5 | | | | 16 | |
Carrying Costs Income | | | 9 | | | | 17 | |
Allowance for Equity Funds Used During Construction | | | 16 | | | | 10 | |
Interest Expense | | | (238 | ) | | | (219 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS | | | 542 | | | | 867 | |
| | | | | | | | |
Income Tax Expense | | | 179 | | | | 293 | |
Equity Earnings of Unconsolidated Subsidiaries | | | - | | | | 2 | |
| | | | | | | | |
NET INCOME | | | 363 | | | | 576 | |
| | | | | | | | |
Less: Net Income Attributable to Noncontrolling Interests | | | 2 | | | | 2 | |
| | | | | | | | |
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS | | | 361 | | | | 574 | |
| | | | | | | | |
Less: Preferred Stock Dividend Requirements of Subsidiaries | | | 1 | | | | 1 | |
| | | | | | | | |
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 360 | | | $ | 573 | |
| | | | | | | | |
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING | | | 406,826,606 | | | | 400,797,993 | |
| | | | | | | | |
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 0.89 | | | $ | 1.43 | |
| | | | | | | | |
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING | | | 407,381,954 | | | | 402,072,098 | |
| | | | | | | | |
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 0.89 | | | $ | 1.43 | |
| | | | | | | | |
CASH DIVIDENDS PAID PER SHARE | | $ | 0.41 | | | $ | 0.41 | |
See Condensed Notes to Condensed Consolidated Financial Statements. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2008March 31, 2009 and December 31, 20072008
(in millions)
(Unaudited)
| | 2008 | | | 2007 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 338 | | | $ | 178 | |
Other Temporary Investments | | | 670 | | | | 365 | |
Accounts Receivable: | | | | | | | | |
Customers | | | 805 | | | | 730 | |
Accrued Unbilled Revenues | | | 370 | | | | 379 | |
Miscellaneous | | | 71 | | | | 60 | |
Allowance for Uncollectible Accounts | | | (59 | ) | | | (52 | ) |
Total Accounts Receivable | | | 1,187 | | | | 1,117 | |
Fuel, Materials and Supplies | | | 1,018 | | | | 967 | |
Risk Management Assets | | | 340 | | | | 271 | |
Regulatory Asset for Under-Recovered Fuel Costs | | | 240 | | | | 11 | |
Margin Deposits | | | 67 | | | | 47 | |
Prepayments and Other | | | 124 | | | | 70 | |
TOTAL | | | 3,984 | | | | 3,026 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Production | | | 20,948 | | | | 20,233 | |
Transmission | | | 7,734 | | | | 7,392 | |
Distribution | | | 12,561 | | | | 12,056 | |
Other (including nuclear fuel and coal mining) | | | 3,633 | | | | 3,445 | |
Construction Work in Progress | | | 3,516 | | | | 3,019 | |
Total | | | 48,392 | | | | 46,145 | |
Accumulated Depreciation and Amortization | | | 16,603 | | | | 16,275 | |
TOTAL - NET | | | 31,789 | | | | 29,870 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 2,239 | | | | 2,199 | |
Securitized Transition Assets | | | 2,080 | | | | 2,108 | |
Spent Nuclear Fuel and Decommissioning Trusts | | | 1,292 | | | | 1,347 | |
Goodwill | | | 76 | | | | 76 | |
Long-term Risk Management Assets | | | 314 | | | | 319 | |
Employee Benefits and Pension Assets | | | 479 | | | | 486 | |
Deferred Charges and Other | | | 785 | | | | 888 | |
TOTAL | | | 7,265 | | | | 7,423 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 43,038 | | | $ | 40,319 | |
| | 2009 | | | 2008 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 710 | | | $ | 411 | |
Other Temporary Investments | | | 215 | | | | 327 | |
Accounts Receivable: | | | | | | | | |
Customers | | | 555 | | | | 569 | |
Accrued Unbilled Revenues | | | 378 | | | | 449 | |
Miscellaneous | | | 70 | | | | 90 | |
Allowance for Uncollectible Accounts | | | (41 | ) | | | (42 | ) |
Total Accounts Receivable | | | 962 | | | | 1,066 | |
Fuel | | | 740 | | | | 634 | |
Materials and Supplies | | | 550 | | | | 539 | |
Risk Management Assets | | | 293 | | | | 256 | |
Regulatory Asset for Under-Recovered Fuel Costs | | | 320 | | | | 284 | |
Margin Deposits | | | 125 | | | | 86 | |
Prepayments and Other | | | 203 | | | | 172 | |
TOTAL | | | 4,118 | | | | 3,775 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Production | | | 22,300 | | | | 21,242 | |
Transmission | | | 7,955 | | | | 7,938 | |
Distribution | | | 12,990 | | | | 12,816 | |
Other (including coal mining and nuclear fuel) | | | 3,772 | | | | 3,741 | |
Construction Work in Progress | | | 3,147 | | | | 3,973 | |
Total | | | 50,164 | | | | 49,710 | |
Accumulated Depreciation and Amortization | | | 16,913 | | | | 16,723 | |
TOTAL - NET | | | 33,251 | | | | 32,987 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 3,837 | | | | 3,783 | |
Securitized Transition Assets | | | 2,011 | | | | 2,040 | |
Spent Nuclear Fuel and Decommissioning Trusts | | | 1,207 | | | | 1,260 | |
Goodwill | | | 76 | | | | 76 | |
Long-term Risk Management Assets | | | 417 | | | | 355 | |
Deferred Charges and Other | | | 948 | | | | 879 | |
TOTAL | | | 8,496 | | | | 8,393 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 45,865 | | | $ | 45,155 | |
See Condensed Notes to Condensed Consolidated Financial Statements. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2008March 31, 2009 and December 31, 20072008
(Unaudited)
| | 2008 | | | 2007 | |
CURRENT LIABILITIES | | (in millions) | |
Accounts Payable | | $ | 1,447 | | | $ | 1,324 | |
Short-term Debt | | | 1,302 | | | | 660 | |
Long-term Debt Due Within One Year | | | 682 | | | | 792 | |
Risk Management Liabilities | | | 330 | | | | 240 | |
Customer Deposits | | | 288 | | | | 301 | |
Accrued Taxes | | | 564 | | | | 601 | |
Accrued Interest | | | 235 | | | | 235 | |
Other | | | 874 | | | | 1,008 | |
TOTAL | | | 5,722 | | | | 5,161 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt | | | 15,325 | | | | 14,202 | |
Long-term Risk Management Liabilities | | | 165 | | | | 188 | |
Deferred Income Taxes | | | 5,150 | | | | 4,730 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 2,827 | | | | 2,952 | |
Asset Retirement Obligations | | | 1,090 | | | | 1,075 | |
Employee Benefits and Pension Obligations | | | 672 | | | | 712 | |
Deferred Gain on Sale and Leaseback – Rockport Plant Unit 2 | | | 132 | | | | 139 | |
Deferred Credits and Other | | | 977 | | | | 1,020 | |
TOTAL | | | 26,338 | | | | 25,018 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 32,060 | | | | 30,179 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 61 | | | | 61 | |
| | | | | | | | |
Commitments and Contingencies (Note 4) | | | | | | | | |
| | | | | | | | |
COMMON SHAREHOLDERS’ EQUITY | | | | | | | | |
Common Stock – $6.50 Par Value Per Share: | | | | | | | | |
| | 2008 | | | 2007 | | | | | | | | | |
Shares Authorized | | | 600,000,000 | | | | 600,000,000 | | | | | | | | | |
Shares Issued | | | 424,538,502 | | | | 421,926,696 | | | | | | | | | |
(21,499,992 shares were held in treasury at September 30, 2008 and December 31, 2007) | | | 2,760 | | | | 2,743 | |
Paid-in Capital | | | 4,444 | | | | 4,352 | |
Retained Earnings | | | 3,861 | | | | 3,138 | |
Accumulated Other Comprehensive Income (Loss) | | | (148 | ) | | | (154 | ) |
TOTAL | | | 10,917 | | | | 10,079 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 43,038 | | | $ | 40,319 | |
| | | | | | | | | | | | | | | | | | | | | | 2009 | | 2008 |
CURRENT LIABILITIES | | | (in millions) |
Accounts Payable | | | $ | 1,126 | | $ | 1,297 |
Short-term Debt | | | | 1,976 | | | 1,976 |
Long-term Debt Due Within One Year | | | | 939 | | | 447 |
Risk Management Liabilities | | | | 179 | | | 134 |
Customer Deposits | | | | 266 | | | 254 |
Accrued Taxes | | | | 614 | | | 634 |
Accrued Interest | | | | 226 | | | 270 |
Regulatory Liability for Over-Recovered Fuel Costs | | | | 155 | | | 66 |
Other | | | | 930 | | | 1,219 |
TOTAL | | | | 6,411 | | | 6,297 |
| | | | | | | |
NONCURRENT LIABILITIES | | | | | | | |
Long-term Debt | | | | 15,904 | | | 15,536 |
Long-term Risk Management Liabilities | | | | 174 | | | 170 |
Deferred Income Taxes | | | | 5,255 | | | 5,128 |
Regulatory Liabilities and Deferred Investment Tax Credits | | | | 2,652 | | | 2,789 |
Asset Retirement Obligations | | | | 1,166 | | | 1,154 |
Employee Benefits and Pension Obligations | | | | 2,162 | | | 2,184 |
Deferred Credits and Other | | | | 1,122 | | | 1,126 |
TOTAL | | | | 28,435 | | | 28,087 |
| | | | | | | |
TOTAL LIABILITIES | | | | 34,846 | | | 34,384 |
| | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | | 61 | | | 61 |
| | | | | | | |
Commitments and Contingencies (Note 4) | | | | | | | |
| | | | | | | |
EQUITY | | | | | | | |
Common Stock Par Value $6.50: | | | | | | | |
| 2009 | | 2008 | | | | | | | | |
Shares Authorized | 600,000,000 | | 600,000,000 | | | | | | | | |
Shares Issued | 428,010,854 | | 426,321,248 | | | | | | | | |
(20,249,992 shares were held in treasury at March 31, 2009 and December 31, 2008) | | | | 2,782 | | | 2,771 |
Paid-in Capital | | | | 4,564 | | | 4,527 |
Retained Earnings | | | | 4,040 | | | 3,847 |
Accumulated Other Comprehensive Income (Loss) | | | | (446) | | | (452) |
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY | | | | 10,940 | | | 10,693 |
| | | | | | | |
Noncontrolling Interests | | | | 18 | | | 17 |
| | | | | | | |
TOTAL EQUITY | | | | 10,958 | | | 10,710 |
| | | | | | | |
TOTAL LIABILITIES AND EQUITY | | | $ | 45,865 | | $ | 45,155 |
See Condensed Notes to Condensed Consolidated Financial Statements. |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the NineThree Months Ended September 30,March 31, 2009 and 2008 and 2007
(in millions)
(Unaudited)
| | 2008 | | | 2007 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 1,228 | | | $ | 858 | |
Less: Discontinued Operations, Net of Tax | | | (1 | ) | | | (2 | ) |
Income Before Discontinued Operations | | | 1,227 | | | | 856 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 1,123 | | | | 1,144 | |
Deferred Income Taxes | | | 397 | | | | 44 | |
Extraordinary Loss, Net of Tax | | | - | | | | 79 | |
Carrying Costs Income | | | (64 | ) | | | (38 | ) |
Allowance for Equity Funds Used During Construction | | | (32 | ) | | | (23 | ) |
Mark-to-Market of Risk Management Contracts | | | 14 | | | | (7 | ) |
Amortization of Nuclear Fuel | | | 72 | | | | 48 | |
Deferred Property Taxes | | | 136 | | | | 118 | |
Fuel Over/Under-Recovery, Net | | | (284 | ) | | | (133 | ) |
Gain on Sales of Assets and Equity Investments, Net | | | (14 | ) | | | (28 | ) |
Change in Other Noncurrent Assets | | | (160 | ) | | | (64 | ) |
Change in Other Noncurrent Liabilities | | | (74 | ) | | | 98 | |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | (69 | ) | | | (209 | ) |
Fuel, Materials and Supplies | | | (49 | ) | | | (13 | ) |
Margin Deposits | | | (20 | ) | | | 39 | |
Accounts Payable | | | 77 | | | | (54 | ) |
Customer Deposits | | | (14 | ) | | | 36 | |
Accrued Taxes, Net | | | (40 | ) | | | (119 | ) |
Accrued Interest | | | (5 | ) | | | 22 | |
Other Current Assets | | | (43 | ) | | | (33 | ) |
Other Current Liabilities | | | (125 | ) | | | (133 | ) |
Net Cash Flows from Operating Activities | | | 2,053 | | | | 1,630 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (2,576 | ) | | | (2,595 | ) |
Change in Other Temporary Investments, Net | | | 106 | | | | (50 | ) |
Purchases of Investment Securities | | | (1,386 | ) | | | (8,632 | ) |
Sales of Investment Securities | | | 912 | | | | 8,849 | |
Acquisitions of Nuclear Fuel | | | (99 | ) | | | (73 | ) |
Acquisitions of Assets | | | (97 | ) | | | (512 | ) |
Proceeds from Sales of Assets | | | 83 | | | | 78 | |
Other | | | (4 | ) | | | - | |
Net Cash Flows Used for Investing Activities | | | (3,061 | ) | | | (2,935 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Common Stock | | | 106 | | | | 116 | |
Issuance of Long-term Debt | | | 2,561 | | | | 1,924 | |
Change in Short-term Debt, Net | | | 642 | | | | 569 | |
Retirement of Long-term Debt | | | (1,582 | ) | | | (870 | ) |
Principal Payments for Capital Lease Obligations | | | (76 | ) | | | (49 | ) |
Dividends Paid on Common Stock | | | (494 | ) | | | (467 | ) |
Other | | | 11 | | | | (23 | ) |
Net Cash Flows from Financing Activities | | | 1,168 | | | | 1,200 | |
| | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 160 | | | | (105 | ) |
Cash and Cash Equivalents at Beginning of Period | | | 178 | | | | 301 | |
Cash and Cash Equivalents at End of Period | | $ | 338 | | | $ | 196 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 657 | | | $ | 549 | |
Net Cash Paid for Income Taxes | | | 126 | | | | 363 | |
Noncash Acquisitions Under Capital Leases | | | 47 | | | | 59 | |
Noncash Acquisition of Land/Mineral Rights | | | 42 | | | | - | |
Construction Expenditures Included in Accounts Payable at September 30, | | | 373 | | | | 265 | |
Acquisition of Nuclear Fuel Included in Accounts Payable at September 30, | | | 66 | | | | 1 | |
Noncash Assumption of Liabilities Related to Acquisitions of Darby, Lawrenceburg and Dresden Plants | | | - | | | | 8 | |
| | 2009 | | | 2008 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 363 | | | $ | 576 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 382 | | | | 363 | |
Deferred Income Taxes | | | 217 | | | | 111 | |
Carrying Costs Income | | | (9 | ) | | | (17 | ) |
Allowance for Equity Funds Used During Construction | | | (16 | ) | | | (10 | ) |
Mark-to-Market of Risk Management Contracts | | | (46 | ) | | | (26 | ) |
Amortization of Nuclear Fuel | | | 13 | | | | 22 | |
Deferred Property Taxes | | | (64 | ) | | | (64 | ) |
Fuel Over/Under-Recovery, Net | | | (95 | ) | | | (57 | ) |
Gain on Sales of Assets | | | (9 | ) | | | (3 | ) |
Change in Other Noncurrent Assets | | | 32 | | | | (119 | ) |
Change in Other Noncurrent Liabilities | | | 18 | | | | (71 | ) |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 102 | | | | 61 | |
Fuel, Materials and Supplies | | | (118 | ) | | | 20 | |
Margin Deposits | | | (39 | ) | | | (4 | ) |
Accounts Payable | | | 3 | | | | (7 | ) |
Customer Deposits | | | 12 | | | | 6 | |
Accrued Taxes, Net | | | (57 | ) | | | 149 | |
Accrued Interest | | | (44 | ) | | | (44 | ) |
Other Current Assets | | | (7 | ) | | | (21 | ) |
Other Current Liabilities | | | (321 | ) | | | (234 | ) |
Net Cash Flows from Operating Activities | | | 317 | | | | 631 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (897 | ) | | | (778 | ) |
Change in Other Temporary Investments, Net | | | 111 | | | | (26 | ) |
Purchases of Investment Securities | | | (179 | ) | | | (491 | ) |
Sales of Investment Securities | | | 158 | | | | 500 | |
Acquisition of Nuclear Fuel | | | (76 | ) | | | (98 | ) |
Proceeds from Sales of Assets | | | 172 | | | | 18 | |
Other | | | (16 | ) | | | (19 | ) |
Net Cash Flows Used for Investing Activities | | | (727 | ) | | | (894 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Common Stock | | | 48 | | | | 45 | |
Change in Short-term Debt, Net | | | - | | | | (251 | ) |
Issuance of Long-term Debt | | | 947 | | | | 916 | |
Retirement of Long-term Debt | | | (93 | ) | | | (289 | ) |
Principal Payments for Capital Lease Obligations | | | (23 | ) | | | (23 | ) |
Dividends Paid on Common Stock | | | (169 | ) | | | (167 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (1 | ) | | | (1 | ) |
Other | | | - | | | | 10 | |
Net Cash Flows from Financing Activities | | | 709 | | | | 240 | |
| | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 299 | | | | (23 | ) |
Cash and Cash Equivalents at Beginning of Period | | | 411 | | | | 178 | |
Cash and Cash Equivalents at End of Period | | $ | 710 | | | $ | 155 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 314 | | | $ | 252 | |
Net Cash Paid for Income Taxes | | | 2 | | | | 36 | |
Noncash Acquisitions Under Capital Leases | | | 6 | | | | 19 | |
Noncash Acquisition of Land/Mineral Rights | | | - | | | | 42 | |
Construction Expenditures Included in Accounts Payable at March 31, | | | 294 | | | | 284 | |
Acquisition of Nuclear Fuel Included in Accounts Payable at March 31, | | | 17 | | | | - | |
See Condensed Notes to Condensed Consolidated Financial Statements. | | | | | | |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS’
EQUITY AND
COMPREHENSIVE INCOME (LOSS)
For the NineThree Months Ended September 30,March 31, 2009 and 2008 and 2007
(in millions)
(Unaudited)
| | Common Stock | | | | | | | | | Accumulated | | | | |
| | Shares | | | Amount | | | Paid-in Capital | | | Retained Earnings | | | Other Comprehensive Income (Loss) | | | Total | |
DECEMBER 31, 2006 | | | 418 | | | $ | 2,718 | | | $ | 4,221 | | | $ | 2,696 | | �� | $ | (223 | ) | | $ | 9,412 | |
FIN 48 Adoption, Net of Tax | | | | | | | | | | | | | | | (17 | ) | | | | | | | (17 | ) |
Issuance of Common Stock | | | 3 | | | | 21 | | | | 95 | | | | | | | | | | | | 116 | |
Common Stock Dividends | | | | | | | | | | | | | | | (467 | ) | | | | | | | (467 | ) |
Other | | | | | | | | | | | 12 | | | | | | | | | | | | 12 | |
TOTAL | | | | | | | | | | | | | | | | | | | | | | | 9,056 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of Tax: | | | | | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $6 | | | | | | | | | | | | | | | | | | | (11 | ) | | | (11 | ) |
Securities Available for Sale, Net of Tax of $3 | | | | | | | | | | | | | | | | | | | (5 | ) | | | (5 | ) |
SFAS 158 Costs Established as a Regulatory Asset Related to the Reapplication of SFAS 71, Net of Tax of $6 | | | | | | | | | | | | | | | | | | | 11 | | | | 11 | |
NET INCOME | | | | | | | | | | | | | | | 858 | | | | | | | | 858 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | 853 | |
SEPTEMBER 30, 2007 | | | 421 | | | $ | 2,739 | | | $ | 4,328 | | | $ | 3,070 | | | $ | (228 | ) | | $ | 9,909 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
DECEMBER 31, 2007 | | | 422 | | | $ | 2,743 | | | $ | 4,352 | | | $ | 3,138 | | | $ | (154 | ) | | $ | 10,079 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
EITF 06-10 Adoption, Net of Tax of $6 | | | | | | | | | | | | | | | (10 | ) | | | | | | | (10 | ) |
SFAS 157 Adoption, Net of Tax of $0 | | | | | | | | | | | | | | | (1 | ) | | | | | | | (1 | ) |
Issuance of Common Stock | | | 3 | | | | 17 | | | | 89 | | | | | | | | | | | | 106 | |
Common Stock Dividends | | | | | | | | | | | | | | | (494 | ) | | | | | | | (494 | ) |
Other | | | | | | | | | | | 3 | | | | | | | | | | | | 3 | |
TOTAL | | | | | | | | | | | | | | | | | | | | | | | 9,683 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of Tax: | | | | | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $4 | | | | | | | | | | | | | | | | | | | 7 | | | | 7 | |
Securities Available for Sale, Net of Tax of $5 | | | | | | | | | | | | | | | | | | | (10 | ) | | | (10 | ) |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $5 | | | | | | | | | | | | | | | | | | | 9 | | | | 9 | |
NET INCOME | | | | | | | | | | | | | | | 1,228 | | | | | | | | 1,228 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | 1,234 | |
SEPTEMBER 30, 2008 | | | 425 | | | $ | 2,760 | | | $ | 4,444 | | | $ | 3,861 | | | $ | (148 | ) | | $ | 10,917 | |
| AEP Common Shareholders | | | | |
| Common Stock | | | | | | Accumulated | | | | |
| | | | | | | | | Other | | | | |
| | | | | Paid-in | | Retained | | Comprehensive | | Noncontrolling | | |
| Shares | | Amount | | Capital | | Earnings | | Income (Loss) | | Interests | | Total |
DECEMBER 31, 2007 | | 422 | | $ | 2,743 | | $ | 4,352 | | $ | 3,138 | | $ | (154) | | $ | 18 | | $ | 10,097 |
| | | | | | | | | | | | | | | | | | | | |
EITF 06-10 Adoption, Net of Tax of $6 | | | | | | | | | | | (10) | | | | | | | | | (10) |
SFAS 157 Adoption, Net of Tax of $0 | | | | | | | | | | | (1) | | | | | | | | | (1) |
Issuance of Common Stock | | 1 | | | 7 | | | 38 | | | | | | | | | | | | 45 |
Common Stock Dividends | | | | | | | | | | | (165) | | | | | | (2) | | | (167) |
Preferred Stock Dividends | | | | | | | | | | | (1) | | | | | | | | | (1) |
Other | | | | | | | | 1 | | | | | | | | | 2 | | | 3 |
TOTAL | | | | | | | | | | | | | | | | | | | | 9,966 |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $17 | | | | | | | | | | | | | | (30) | | | | | | (30) |
Securities Available for Sale, Net of Tax of $3 | | | | | | | | | | | | | | (6) | | | | | | (6) |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $2 | | | | | | | | | | | | | | 3 | | | | | | 3 |
NET INCOME | | | | | | | | | | | 574 | | | | | | 2 | | | 576 |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | 543 |
| | | | | | | | | | | | | | | | | | | | |
MARCH 31, 2008 | | 423 | | $ | 2,750 | | $ | 4,391 | | $ | 3,535 | | $ | (187) | | $ | 20 | | $ | 10,509 |
| | | | | | | | | | | | | | | | | | | | |
DECEMBER 31, 2008 | | 426 | | $ | 2,771 | | $ | 4,527 | | $ | 3,847 | | $ | (452) | | $ | 17 | | $ | 10,710 |
| | | | | | | | | | | | | | | | | | | | |
Issuance of Common Stock | | 2 | | | 11 | | | 37 | | | | | | | | | | | | 48 |
Common Stock Dividends | | | | | | | | | | | (167) | | | | | | (2) | | | (169) |
Preferred Stock Dividends | | | | | | | | | | | (1) | | | | | | | | | (1) |
Other | | | | | | | | | | | | | | | | | 1 | | | 1 |
TOTAL | | | | | | | | | | | | | | | | | | | | 10,589 |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $1 | | | | | | | | | | | | | | 3 | | | | | | 3 |
Securities Available for Sale, Net of Tax of $1 | | | | | | | | | | | | | | (2) | | | | | | (2) |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $3 | | | | | | | | | | | | | | 5 | | | | | | 5 |
NET INCOME | | | | | | | | | | | 361 | | | | | | 2 | | | 363 |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | 369 |
| | | | | | | | | | | | | | | | | | | | |
MARCH 31, 2009 | | 428 | | $ | 2,782 | | $ | 4,564 | | $ | 4,040 | | $ | (446) | | $ | 18 | | $ | 10,958 |
See Condensed Notes to Condensed Consolidated Financial Statements.Statements |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX TO CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
| |
1. | Significant Accounting Matters |
2. | New Accounting Pronouncements and Extraordinary Item |
3. | Rate Matters |
4. | Commitments, Guarantees and Contingencies |
5. | Acquisitions, Dispositions and Discontinued OperationsBenefit Plans |
6. | Benefit PlansBusiness Segments |
7. | Business SegmentsDerivatives, Hedging and Fair Value Measurements |
8. | Income Taxes |
9. | Financing Activities |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
| CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS |
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. | SIGNIFICANT ACCOUNTING MATTERS |
General
The accompanying unaudited condensed consolidated financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.
In the opinion of management, the unaudited interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our net income, financial position and cash flows for the interim periods. The net income for the three and nine months ended September 30, 2008 areMarch 31, 2009 is not necessarily indicative of results that may be expected for the year ending December 31, 2008.2009. The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 20072008 consolidated financial statements and notes thereto, which are included in our Annual Report on Form 10-K for the year ended December 31, 20072008 as filed with the SEC on February 28, 2008.27, 2009.
Earnings Per Share (EPS)
The following table presents our basic and diluted EPS calculations included on our Condensed Consolidated Statements of Income:
| | Three Months Ended September 30, | |
| | 2008 | | | 2007 | |
| | (in millions, except per share data) | |
| | | | | $/share | | | | | | $/share | |
Earnings Applicable to Common Stock | | $ | 374 | | | | | | $ | 407 | | | | |
| | | | | | | | | | | | | | |
Average Number of Basic Shares Outstanding | | | 402.3 | | | $ | 0.93 | | | | 399.2 | | | $ | 1.02 | |
Average Dilutive Effect of: | | | | | | | | | | | | | | | | |
Performance Share Units | | | 1.3 | | | | - | | | | 0.5 | | | | - | |
Stock Options | | | 0.1 | | | | - | | | | 0.3 | | | | - | |
Restricted Stock Units | | | 0.1 | | | | - | | | | 0.1 | | | | - | |
Restricted Shares | | | 0.1 | | | | - | | | | 0.1 | | | | - | |
Average Number of Diluted Shares Outstanding | | | 403.9 | | | $ | 0.93 | | | | 400.2 | | | $ | 1.02 | |
| | Nine Months Ended September 30, | |
| | 2008 | | | 2007 | |
| | (in millions, except per share data) | |
| | | | | $/share | | | | | | $/share | |
Earnings Applicable to Common Stock | | $ | 1,228 | | | | | | $ | 858 | | | | |
| | | | | | | | | | | | | | |
Average Number of Basic Shares Outstanding | | | 401.5 | | | $ | 3.06 | | | | 398.4 | | | $ | 2.15 | |
Average Dilutive Effect of: | | | | | | | | | | | | | | | | |
Performance Share Units | | | 1.0 | | | | (0.01 | ) | | | 0.6 | | | | - | |
Stock Options | | | 0.2 | | | | - | | | | 0.4 | | | | - | |
Restricted Stock Units | | | 0.1 | | | | - | | | | 0.1 | | | | - | |
Restricted Shares | | | 0.1 | | | | - | | | | 0.1 | | | | - | |
Average Number of Diluted Shares Outstanding | | | 402.9 | | | $ | 3.05 | | | | 399.6 | | | $ | 2.15 | |
| | Three Months Ended March 31, | |
| | 2009 | | | 2008 | |
| | (in millions, except per share data) | |
| | | | | $/share | | | | | | $/share | |
Earnings Applicable to AEP Common Shareholders | | $ | 360 | | | | | | $ | 573 | | | | |
| | | | | | | | | | | | | | |
Weighted Average Number of Basic Shares Outstanding | | | 406.8 | | | $ | 0.89 | | | | 400.8 | | | $ | 1.43 | |
Weighted Average Dilutive Effect of: | | | | | | | | | | | | | | | | |
Performance Share Units | | | 0.5 | | | | - | | | | 0.9 | | | | - | |
Stock Options | | | - | | | | - | | | | 0.2 | | | | - | |
Restricted Stock Units | | | 0.1 | | | | - | | | | 0.1 | | | | - | |
Restricted Shares | | | - | | | | - | | | | 0.1 | | | | - | |
Weighted Average Number of Diluted Shares Outstanding | | | 407.4 | | | $ | 0.89 | | | | 402.1 | | | $ | 1.43 | |
The assumed conversion of our share-based compensation does not affect net earnings for purposes of calculating diluted earnings per share.
Options to purchase 146,900618,916 and 83,550146,900 shares of common stock were outstanding at September 30,March 31, 2009 and 2008, and 2007, respectively, but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the quarter-end market price of the common shares and, therefore, the effect would be antidilutive.
Variable Interest Entities
FIN 46R is a consolidation model that considers risk absorption of a variable interest entity (VIE), also referred to as variability. Entities are required to consolidate a VIE when it is determined that they are the primary beneficiary of that VIE, as defined by FIN 46R. In determining whether we are the primary beneficiary of a VIE, we consider factors such as equity at risk, the amount of the VIE’s variability we absorb, guarantees of indebtedness, voting rights including kick-out rights, power to direct the VIE and other factors. We believe that significant assumptions and judgments have been consistently applied and that there are no other reasonable judgments or assumptions that would have resulted in a different conclusion.
We are the primary beneficiary of Sabine, DHLC, JMG and a protected cell of EIS. We hold a variable interest in Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series). In addition, we have not provided financial or other support to any VIE that was not previously contractually required.
Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo has guaranteed the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee which is included in Fuel and Other Consumables Used for Electric Generation on our Condensed Consolidated Statements of Income. Based on these facts, management has concluded SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the three months ended March 31, 2009 and 2008 were $35 million and $20 million, respectively. See the tables below for the classification of Sabine’s assets and liabilities on our Condensed Consolidated Balance Sheets.
DHLC is a wholly-owned subsidiary of SWEPCo. DHLC is a mining operator who sells 50% of the lignite produced to SWEPCo and 50% to Cleco Corporation, a nonaffiliated company. SWEPCo and Cleco Corporation share half of the executive board seats, with equal voting rights and each entity guarantees a 50% share of DHLC’s debt. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. Based on the structure and equity ownership, management has concluded that SWEPCo is the primary beneficiary and is required to consolidate DHLC. SWEPCo’s total billings from DHLC for the three months ended March 31, 2009 and 2008 were $11 million and $12 million, respectively. These billings are included in Fuel and Other Consumables Used for Electric Generation on our Condensed Consolidated Statements of Income. See the tables below for the classification of DHLC assets and liabilities on our Condensed Consolidated Balance Sheets.
OPCo has a lease agreement with JMG to finance OPCo’s Flue Gas Desulfurization (FGD) system installed on OPCo’s Gavin Plant. The PUCO approved the original lease agreement between OPCo and JMG. JMG has a capital structure of substantially all debt from pollution control bonds and other debt. JMG owns and leases the FGD to OPCo. JMG is considered a single-lessee leasing arrangement with only one asset. OPCo’s lease payments are the only form of repayment associated with JMG’s debt obligations even though OPCo does not guarantee JMG’s debt. The creditors of JMG have no recourse to any AEP entity other than OPCo for the lease payment. OPCo does not have any ownership interest in JMG. Based on the structure of the entity, management has concluded OPCo is the primary beneficiary and is required to consolidate JMG. OPCo’s total billings from JMG for the three months ended March 31, 2009 and 2008 were $17 million and $12 million, respectively. See the tables below for the classification of JMG’s assets and liabilities on our Condensed Consolidated Balance Sheets.
EIS is a captive insurance company with multiple protected cells in which our subsidiaries participate in one protected cell for approximately ten lines of insurance. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP system is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance. Our subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on the structure of the protected cell, management has concluded that we are the primary beneficiary and that we are required to consolidate the protected cell. Our insurance premium payments to EIS for the three months ended March 31, 2009 and 2008 were $17 million in both periods. See the tables below for the classification of EIS’s assets and liabilities on our Condensed Consolidated Balance Sheets.
The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that would be eliminated upon consolidation.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
March 31, 2009
(in millions)
| | SWEPCo Sabine | | | SWEPCo DHLC | | | OPCo JMG | | | EIS | |
ASSETS | | | | | | | | | | | | |
Current Assets | | $ | 34 | | | $ | 18 | | | $ | 13 | | | $ | 118 | |
Net Property, Plant and Equipment | | | 122 | | | | 32 | | | | 417 | | | | - | |
Other Noncurrent Assets | | | 30 | | | | 11 | | | | 1 | | | | 1 | |
Total Assets | | $ | 186 | | | $ | 61 | | | $ | 431 | | | $ | 119 | |
| | | | | | | | | | | | | | | | |
LIABILITIES AND EQUITY | | | | | | | | | | | | | | | | |
Current Liabilities | | $ | 34 | | | $ | 12 | | | $ | 156 | | | $ | 41 | |
Noncurrent Liabilities | | | 152 | | | | 45 | | | | 257 | | | | 64 | |
Equity | | | - | | | | 4 | | | | 18 | | | | 14 | |
Total Liabilities and Equity | | $ | 186 | | | $ | 61 | | | $ | 431 | | | $ | 119 | |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
VARIABLE INTEREST ENTITIES
December 31, 2008
(in millions)
| | SWEPCo Sabine | | | SWEPCo DHLC | | | OPCo JMG | | | EIS | |
ASSETS | | | | | | | | | | | | |
Current Assets | | $ | 33 | | | $ | 22 | | | $ | 11 | | | $ | 107 | |
Net Property, Plant and Equipment | | | 117 | | | | 33 | | | | 423 | | | | - | |
Other Noncurrent Assets | | | 24 | | | | 11 | | | | 1 | | | | 2 | |
Total Assets | | $ | 174 | | | $ | 66 | | | $ | 435 | | | $ | 109 | |
| | | | | | | | | | | | | | | | |
LIABILITIES AND EQUITY | | | | | | | | | | | | | | | | |
Current Liabilities | | $ | 32 | | | $ | 18 | | | $ | 161 | | | $ | 30 | |
Noncurrent Liabilities | | | 142 | | | | 44 | | | | 257 | | | | 60 | |
Equity | | | - | | | | 4 | | | | 17 | | | | 19 | |
Total Liabilities and Equity | | $ | 174 | | | $ | 66 | | | $ | 435 | | | $ | 109 | |
In September 2007, we and Allegheny Energy Inc. (AYE) formed a joint venture by creating Potomac-Appalachian Transmission Highline, LLC (PATH). PATH is a series limited liability company and was created to construct a high-voltage transmission line project in the PJM region. PATH consists of the “Ohio Series,” the “West Virginia Series (PATH-WV),” both owned equally by AYE and us and the “Allegheny Series” which is 100% owned by AYE. Provisions exist within the PATH-WV agreement that make it a VIE. The “Ohio Series” does not include the same provisions that make PATH-WV a VIE. The other series are not considered VIEs. We are not required to consolidate PATH-WV as we are not the primary beneficiary, although we hold a significant interest in PATH-WV. Our equity investment in PATH-WV is included in Deferred Charges and Other on our Condensed Consolidated Balance Sheets. We and AYE share the returns and losses equally in PATH-WV. Our subsidiaries and AYE’s subsidiaries provide services to the PATH companies through service agreements. At the current time, PATH-WV has no debt outstanding. However, when debt is issued, the debt to equity ratio in each series will be consistent with other regulated utilities and the entities are designed to maintain this financing structure. The entities recover costs through regulated rates.
Given the structure of the entity, we may be required to provide future financial support to PATH-WV in the form of a capital call. This would be considered an increase to our investment in the entity. Our maximum exposure to loss is to the extent of our investment. Currently the entity has no debt financing. The likelihood of such a loss is remote since the FERC approved PATH-WV’s request for regulatory recovery of cost and a return on the equity invested.
Our investment in PATH-WV was:
| | March 31, 2009 | | December 31, 2008 | |
| | As Reported on the Consolidated Balance Sheet | | | Maximum Exposure | | As Reported on the Consolidated Balance Sheet | | | Maximum Exposure | |
| | | | | (in millions) | | | | |
Capital Contribution from Parent | | $ | 4 | | | $ | 4 | | | $ | 4 | | | $ | 4 | |
Retained Earnings | | | 1 | | | | 1 | | | | 2 | | | | 2 | |
| | | | | | | | | | | | | | | | |
Total Investment in PATH-WV | | $ | 5 | | | $ | 5 | | | $ | 6 | | | $ | 6 | |
Revenue Recognition – Traditional Electricity Supply and Demand
Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. We recognize the revenues on our Condensed Consolidated Statements of Income upon delivery of the energy to the customer and include unbilled as well as billed amounts.
Most of the power produced at the generation plants of the AEP East companies is sold to PJM, the RTO operating in the east service territory. We then purchase power from PJM to supply our customers. Generally, these power sales and purchases are reported on a net basis as revenues on our Condensed Consolidated Statements of Income. However, in the first quarter of 2009, there were times when we were a purchaser of power from PJM to serve retail load. These purchases were recorded gross as Purchased Electricity for Resale on our Condensed Consolidated Statements of Income. Other RTOs in which we operate do not function in the same manner as PJM. They function as balancing organizations and not as exchanges.
Physical energy purchases, including those from RTOs, that are identified as non-trading, are accounted for on a gross basis in Purchased Electricity for Resale on our Condensed Consolidated Statements of Income.
CSPCo and OPCo Revised Depreciation Rates
Effective January 1, 2009, we revised book depreciation rates for CSPCo and OPCo generating plants consistent with a recently completed depreciation study. OPCo’s overall higher depreciation rates primarily related to shortened depreciable lives for certain OPCo generating facilities. The impact of the change in depreciation rates was an increase in OPCo’s depreciation expense of $17 million and a decrease in CSPCo’s depreciation expense of $4 million when comparing the three months ended March 31, 2009 and 2008.
Acquisition – Oxbow Mine Lignite (Utility Operations segment)
In April 2009, SWEPCo and its wholly-owned lignite mining subsidiary, Dolet Hills Mining Company, LLC (DHLC), agreed to purchase 50% of the Oxbow Mine lignite reserves and 100% of all associated mining equipment and assets from The North American Coal Corporation and its affiliates, Red River Mining Company and Oxbow Property Company, LLC for $42 million. Cleco Power LLC (Cleco) will acquire the remaining 50% of the lignite reserves. Consummation of the transaction is subject to regulatory approval by the LPSC and the APSC and the transfer of other regulatory instruments. If approved, DHLC will acquire and own the Oxbow Mine mining equipment and related assets and it will operate the Oxbow Mine. The Oxbow Mine is located near Coushatta, Louisiana and will be used as one of the fuel sources for SWEPCo’s and Cleco’s jointly-owned Dolet Hills Generating Station.
Supplementary Information
| | Three Months Ended September 30, | | | Nine Months Ended September 30, | |
| | 2008 | | | 2007 | | | 2008 | | | 2007 | |
Related Party Transactions | | (in millions) | | | (in millions) | |
AEP Consolidated Revenues – Utility Operations: | | | | | | | | | | | | |
Power Pool Purchases – Ohio Valley Electric Corporation (43.47% owned) | | $ | (14 | ) | | $ | (12 | ) | | $ | (40 | ) | | $ | (16 | ) |
AEP Consolidated Revenues – Other: | | | | | | | | | | | | | | | | |
Ohio Valley Electric Corporation – Barging and Other Transportation Services (43.47% Owned) | | | 7 | | | | 7 | | | | 21 | | | | 24 | |
AEP Consolidated Expenses – Purchased Energy for Resale: | | | | | | | | | | | | | | | | |
Ohio Valley Electric Corporation (43.47% Owned) | | | 70 | | | | 59 | | | | 194 | | | | 164 | |
Sweeny Cogeneration Limited Partnership (a) | | | - | | | | 27 | | | | - | | | | 86 | |
| | Three Months Ended March 31, | |
| | 2009 | | | 2008 | |
Related Party Transactions | | (in millions) | |
AEP Consolidated Revenues – Utility Operations: | | | | | | |
Power Pool Purchases – Ohio Valley Electric Corporation (43.47% owned) (a) | | $ | - | | | $ | (13 | ) |
AEP Consolidated Revenues – Other: | | | | | | | | |
Ohio Valley Electric Corporation – Barging and Other Transportation Services (43.47% Owned) | | | 9 | | | | 9 | |
AEP Consolidated Expenses – Purchased Electricity for Resale: | | | | | | | | |
Ohio Valley Electric Corporation (43.47% Owned) | | | 70 | | | | 63 | |
(a) | In October 2007, we sold our 50% ownership2006, the AEP Power Pool began purchasing power from OVEC as part of risk management activities. The agreement expired in the Sweeny Cogeneration Limited Partnership.May 2008 and subsequently ended in December 2008. |
Reclassifications
Certain prior period financial statement items have been reclassified to conform to current period presentation. See “FSP FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1)” section of Note 2 for discussion of changes in netting certain balance sheet amounts. These reclassifications had no impact on our previously reported net income or changes in shareholders’ equity.
2. | NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEM |
NEW ACCOUNTING PRONOUNCEMENTS
Upon issuance of final pronouncements, we thoroughly review the new accounting literature to determine theits relevance, if any, to our business. The following represents a summary of newfinal pronouncements issued or implemented in 20082009 and standards issued but not implemented that we have determined relate to our operations.
Pronouncements Adopted During the First Quarter of 2009
The following standards were effective during the first quarter of 2009. Consequently, the financial statements and footnotes reflect their impact.
SFAS 141 (revised 2007) “Business Combinations” (SFAS 141R)
In December 2007, the FASB issued SFAS 141R, improving financial reporting about business combinations and their effects. It establishesestablished how the acquiring entity recognizes and measures the identifiable assets acquired, liabilities assumed, goodwill acquired, any gain on bargain purchases and any noncontrolling interest in the acquired entity. SFAS 141R no longer allows acquisition-related costs to be included in the cost of the business combination, but rather expensed in the periods they are incurred, with the exception of the costs to issue debt or equity securities which shall be recognized in accordance with other applicable GAAP. SFAS 141RThe standard requires disclosure of information for a business combination that occurs during the accounting period or prior to the issuance of the financial statements for the accounting period. SFAS 141R can affect tax positions on previous acquisitions. We do not have any such tax positions that result in adjustments.
In April 2009, the FASB issued FSP SFAS 141(R)-1 “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies.” The standard clarifies accounting and disclosure for contingencies arising in business combinations. It was effective January 1, 2009.
We adopted SFAS 141R, including the FSP, effective January 1, 2009. It is effective prospectively for business combinations with an acquisition date on or after the beginning of the first annual reporting period after December 15, 2008. Early adoption is prohibited.January 1, 2009. We will adopt SFAS 141R effective January 1, 2009 and apply it to any future business combinations on or after that date.combinations.
SFAS 157 “Fair Value Measurements” (SFAS 157)
In September 2006, the FASB issued 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” (SFAS 157-1) which amends SFAS 157 to exclude SFAS 13 “Accounting for Leases” (SFAS 13) 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” (SFAS 157-2) 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 FSP was effective upon issuance. The adoption of this standard had no impact on our financial statements.
We partially adopted SFAS 157 effective January 1, 2008. 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. 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.
In accordance with SFAS 157, assets and liabilities are classified based on the inputs utilized in the fair value measurement. SFAS 157 provides definitions for two types of inputs: observable and unobservable. Observable inputs are valuation inputs that reflect the assumptions market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the reporting entity. Unobservable inputs are valuation inputs that reflect the reporting entity’s own assumptions about the assumptions market participants would use in pricing the asset or liability developed based on the best information in the circumstances.
As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).
Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 1 inputs primarily consist of exchange traded contracts, listed equities and U.S. government treasury securities that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 inputs are inputs other than quoted prices included within level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in level 1, OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market and certain non-exchange-traded debt securities.
Level 3 inputs are unobservable inputs for the asset or liability. Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions.
Risk Management Contracts include exchange traded, OTC and bilaterally executed derivative contracts. Exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified within level 1. Other actively traded derivative fair values are verified using broker or dealer quotations, similar observable market transactions in either the listed or OTC markets, or valued using pricing models where significant valuation inputs are directly or indirectly observable in active markets. Derivative instruments, primarily swaps, forwards, and options that meet these characteristics are classified within level 2. Bilaterally executed agreements are derivative contracts entered into directly with third parties, and at times these instruments may be complex structured transactions that are tailored to meet the specific customer’s energy requirements. Structured transactions utilize pricing models that are widely accepted in the energy industry to measure fair value. Generally, we use a consistent modeling approach to value similar instruments. Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in level 2. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. In addition, long-dated and illiquid complex or structured transactions or FTRs can introduce the need for internally developed modeling inputs based upon extrapolations and assumptions of observable market data to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in level 3. In certain instances, the fair values of the transactions that use internally developed model inputs, classified as level 3 are offset partially or in full, by transactions included in level 2 where observable market data exists for the offsetting transaction.
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2008. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of September 30, 2008 | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in millions) | |
| | | | | | | | | | | | | | | |
Cash and Cash Equivalents (a) | | $ | 271 | | | $ | - | | | $ | - | | | $ | 67 | | | $ | 338 | |
Other Temporary Investments: | | | | | | | | | | | | | | | | | | | | |
Cash and Cash Equivalents (b) | | $ | 147 | | | $ | - | | | $ | - | | | $ | 22 | | | $ | 169 | |
Debt Securities (c) | | | - | | | | 490 | | | | - | | | | - | | | | 490 | |
Equity Securities (d) | | | 11 | | | | - | | | | - | | | | - | | | | 11 | |
Total Other Temporary Investments | | $ | 158 | | | $ | 490 | | | $ | - | | | $ | 22 | | | $ | 670 | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets: | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (e) | | $ | 41 | | | $ | 2,423 | | | $ | 75 | | | $ | (1,959 | ) | | $ | 580 | |
Cash Flow and Fair Value Hedges (e) | | | 9 | | | | 37 | | | | - | | | | (15 | ) | | | 31 | |
Dedesignated Risk Management Contracts (f) | | | - | | | | - | | | | - | | | | 43 | | | | 43 | |
Total Risk Management Assets | | $ | 50 | | | $ | 2,460 | | | $ | 75 | | | $ | (1,931 | ) | | $ | 654 | |
| | | | | | | | | | | | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts: | | | | | | | | | | | | | | | | | | | | |
Cash and Cash Equivalents (g) | | $ | - | | | $ | 4 | | | $ | - | | | $ | 6 | | | $ | 10 | |
Debt Securities (h) | | | - | | | | 837 | | | | - | | | | - | | | | 837 | |
Equity Securities (d) | | | 445 | | | | - | | | | - | | | | - | | | | 445 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | | $ | 445 | | | $ | 841 | | | $ | - | | | $ | 6 | | | $ | 1,292 | |
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 924 | | | $ | 3,791 | | | $ | 75 | | | $ | (1,836 | ) | | $ | 2,954 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities: | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (e) | | $ | 52 | | | $ | 2,279 | | | $ | 68 | | | $ | (1,926 | ) | | $ | 473 | |
Cash Flow and Fair Value Hedges (e) | | | - | | | | 37 | | | | - | | | | (15 | ) | | | 22 | |
Total Risk Management Liabilities | | $ | 52 | | | $ | 2,316 | | | $ | 68 | | | $ | (1,941 | ) | | $ | 495 | |
(a) | Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions. Level 1 amounts primarily represent investments in money market funds. |
(b) | Amounts in “Other” column primarily represent cash deposits with third parties. Level 1 amounts primarily represent investments in money market funds. |
(c) | Amounts represent Variable Rate Demand Notes. |
(d) | Amounts represent publicly traded equity securities. |
(e) | Amounts in “Other” column primarily represent counterparty netting of risk management contracts and associated cash collateral under FSP FIN 39-1. |
(f) | “Dedesignated Risk Management Contracts” are contracts that were originally MTM but were subsequently elected as normal under SFAS 133. At the time of the normal election, the MTM value was frozen and no longer fair valued. This will be amortized into Utility Operations Revenues over the remaining life of the contract. |
(g) | Amounts in “Other” column primarily represent accrued interest receivables to/from financial institutions. Level 2 amounts primarily represent investments in money market funds. |
(h) | Amounts represent corporate, municipal and treasury bonds. |
The following tables set forth a reconciliation of changes in the fair value of net trading derivatives and other investments classified as level 3 in the fair value hierarchy:
Three Months Ended September 30, 2008 | | Net Risk Management Assets (Liabilities) | | | Other Temporary Investments | | | Investments in Debt Securities | |
| | (in millions) | |
Balance as of July 1, 2008 | | $ | (8 | ) | | $ | - | | | $ | - | |
Realized (Gain) Loss Included in Earnings (or Changes in Net Assets) (a) | | | 17 | | | | - | | | | - | |
Unrealized Gain (Loss) Included in Earnings (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | | (7 | ) | | | - | | | | - | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | | - | | | | - | | | | - | |
Purchases, Issuances and Settlements | | | - | | | | - | | | | - | |
Transfers in and/or out of Level 3 (b) | | | (10 | ) | | | - | | | | - | |
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | | | 15 | | | | - | | | | - | |
Balance as of September 30, 2008 | | $ | 7 | | | $ | - | | | $ | - | |
Nine Months Ended September 30, 2008 | | Net Risk Management Assets (Liabilities) | | | Other Temporary Investments | | | Investments in Debt Securities | |
| | (in millions) | |
Balance as of January 1, 2008 | | $ | 49 | | | $ | - | | | $ | - | |
Realized (Gain) Loss Included in Earnings (or Changes in Net Assets) (a) | | | - | | | | - | | | | - | |
Unrealized Gain (Loss) Included in Earnings (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | | 4 | | | | - | | | | - | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | | - | | | | - | | | | - | |
Purchases, Issuances and Settlements | | | - | | | | (118 | ) | | | (17 | ) |
Transfers in and/or out of Level 3 (b) | | | (35 | ) | | | 118 | | | | 17 | |
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | | | (11 | ) | | | - | | | | - | |
Balance as of September 30, 2008 | | $ | 7 | | | $ | - | | | $ | - | |
(a) | Included in revenues on our Condensed Consolidated Statements of Income. |
(b) | “Transfers in and/or out of Level 3” represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period. |
(c) | “Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected on the Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities. |
SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159)
In February 2007, the FASB issued 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.
SFAS 160 “Noncontrolling Interest in Consolidated Financial Statements” (SFAS 160)
In December 2007, the FASB issued SFAS 160, modifying reporting for noncontrolling interest (minority interest) in consolidated financial statements. ItThe statement requires noncontrolling interest be reported in equity and establishes a new framework for recognizing net income or loss and comprehensive income by the controlling interest. Upon deconsolidation due to loss of control over a subsidiary, the standard requires a fair value remeasurement of any remaining noncontrolling equity investment to be used to properly recognize the gain or loss. SFAS 160 requires specific disclosures regarding changes in equity interest of both the controlling and noncontrolling parties and presentation of the noncontrolling equity balance and income or loss for all periods presented.
SFAS 160 is effective for interim and annual periods in fiscal years beginning after December 15, 2008. The statement is applied prospectively upon adoption. Early adoption is prohibited. Upon adoption, prior period financial statements will be restated for the presentation of the noncontrolling interest for comparability. We expect that the adoption of this standard will have an immaterial impact on our financial statements. We will adoptadopted SFAS 160 effective January 1, 2009.2009 and retrospectively applied the standard to prior periods. The retrospective application of this standard:
· | Reclassifies Minority Interest Expense of $1 million and Interest Expense of $1 million for the three months ended March 31, 2008 as Net Income Attributable to Noncontrolling Interest below Net Income in the presentation of Earnings Attributable to AEP Common Shareholders in our Condensed Consolidated Statements of Income. |
· | Repositions Preferred Stock Dividend Requirements of Subsidiaries of $1 million for the three months ended March 31, 2008 below Net Income in the presentation of Earnings Attributable to AEP Common Shareholders in our Condensed Consolidated Statements of Income. |
· | Reclassifies minority interest of $17 million as of December 31, 2008 previously included in Deferred Credits and Other and Total Liabilities as Noncontrolling Interest in Total Equity on our Consolidated Balance Sheets. |
· | Separately reflects changes in Noncontrolling Interest in the Statements of Changes in Equity and Comprehensive Income (Loss). |
· | Reclassifies dividends paid to noncontrolling interests of $2 million for the three months ended March 31, 2008 from Operating Activities to Financing Activities in our Condensed Consolidated Statements of Cash Flows. |
SFAS 161 “Disclosures about Derivative Instruments and Hedging Activities” (SFAS 161)
In March 2008, the FASB issued SFAS 161, enhancing disclosure requirements for derivative instruments and hedging activities. Affected entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how an entity accounts for derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS 161The standard requires that objectives for using derivative instruments be disclosed in terms of the primary underlying risk and accounting designation.
We adopted SFAS 161 effective January 1, 2009. This standard is intended to improve upon the existing disclosure framework in SFAS 133.
SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008. We expect this standard to increaseincreased our disclosure requirementsdisclosures related to derivative instruments and hedging activities. It encourages retrospective application to comparative disclosureSee “Derivatives and Hedging ” section of Note 7 for earlier periods presented. We will adopt SFAS 161 effective January 1, 2009.further information.
SFAS 162 “The Hierarchy of Generally Accepted Accounting Principles” (SFAS 162)EITF Issue No. 08-5 “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (EITF 08-5) |
In May 2008, the FASB issued SFAS 162, clarifying the sources of generally accepted accounting principles in descending order of authority. The statement specifies that the reporting entity, not its auditors, is responsible for its compliance with GAAP.
SFAS 162 is effective 60 days after the SEC approves the Public Company Accounting Oversight Board’s amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” We expect the adoption of this standard will have no impact on our financial statements. We will adopt SFAS 162 when it becomes effective.
EITF Issue No. 06-10 “Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements” (EITF 06-10)
In March 2007, the FASB ratified 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.
EITF Issue No. 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards” (EITF 06-11)
In June 2007, the FASB ratified the EITF 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. 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.
We adopted EITF 06-11 effective January 1, 2008. The adoption of this standard had an immaterial impact on our financial statements.
EITF Issue No. 08-5 “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (EITF 08-5)
In September 2008, the FASB ratified the EITF consensus on liabilities with third-party credit enhancements when the liability is measured and disclosed at fair value. The consensus treats the liability and the credit enhancement as two units of accounting. Under the consensus, the fair value measurement of the liability does not include the effect of the third-party credit enhancement. Consequently, changes in the issuer’s credit standing without the support of the credit enhancement affect the fair value measurement of the issuer’s liability. Entities will need to provide disclosures about the existence of any third-party credit enhancements related to their liabilities.
EITF 08-5 is effective for the first reporting period beginning after December 15, 2008. It will be applied prospectively upon adoption with the effect of initial application included as a change in fair value of the liability in the period of adoption. In the period of adoption, entities must disclose the valuation method(s) used to measure the fair value of liabilities within its scope and any change in the fair value measurement method that occurs as a result of its initial application. Early adoption is permitted. Although we have not completed our analysis, we expect that
We adopted EITF 08-5 effective January 1, 2009. It will be applied prospectively with the adoptioneffect of this standard will haveinitial application included as a change in fair value of the liability.
EITF Issue No. 08-6 “Equity Method Investment Accounting Considerations” (EITF 08-6)
In November 2008, the FASB ratified the consensus on equity method investment accounting including initial and allocated carrying values and subsequent measurements. It requires initial carrying value be determined using the SFAS 141R cost allocation method. When an immaterialinvestee issues shares, the equity method investor should treat the transaction as if the investor sold part of its interest.
We adopted EITF 08-6 effective January 1, 2009 with no impact on our financial statements. We will adopt this standard effective January 1, 2009.It was applied prospectively.
FSP EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (EITF 03-6-1)
In June 2008, the FASB issued EITF 03-6-1 addressingaddressed whether instruments granted in share-based payment transactions are participating securities prior to vesting and determined that the instruments need to be included in earnings allocation in computing EPS under the two-class method described in SFAS 128 “Earnings per Share.”
We adopted EITF 03-6-1 is effective for interim and annual periods in fiscal years beginning after December 15, 2008.January 1, 2009. The statement is applied retrospectively upon adoption. Early adoption is prohibited. Upon adoption, prior period financial statements will be restated for comparability. Although we have not completed our analysis, we expect that the adoption of this standard will havehad an immaterial impact on our financial statements. We will adopt EITF 03-6-1 effective January 1, 2009.
FSP SFAS 133-1 and FIN 45-4 “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment
of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of
FASB Statement No. 161” (SFAS 133-1 and FIN 45-4)
In September 2008, the FASB issued SFAS 133-1 and FIN 45-4 as amendments to original statements SFAS 133 and FIN 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” Under the SFAS 133 requirements, the seller of a credit derivative shall disclose the following information for each derivative, including credit derivatives embedded in a hybrid instrument, even if the likelihood of payment is remote:
(a) | The nature of the credit derivative. |
(b) | The maximum potential amount of future payments. |
(c) | The fair value of the credit derivative. |
(d) | The nature of any recourse provisions and any assets held as collateral or by third parties. |
Further, the standard requires the disclosure of current payment status/performance risk of all FIN 45 guarantees. In the event an entity uses internal groupings, the entity shall disclose how those groupings are determined and used for managing risk.
The standard is effective for interim and annual reporting periods ending after November 15, 2008. Upon adoption, the guidance will be prospectively applied. We expect that the adoption of this standard will have an immaterial impact on our financial statements but increase our FIN 45 guarantees disclosure requirements. We will adopt the standard effective December 31, 2008.
FSP SFAS 142-3 “Determination of the Useful Life of Intangible Assets” (SFAS 142-3)
In April 2008, the FASB issued SFAS 142-3 amending factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS 142, “Goodwill and Other Intangible Assets.”asset. The standard is expected to improve consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure its fair value.
We adopted SFAS 142-3 is effective for interim and annual periods in fiscal years beginning after December 15, 2008. Early adoptionJanuary 1, 2009. The guidance is prohibited. Upon adoption, the guidance within SFAS 142-3 will be prospectively applied to intangible assets acquired after the effective date. We expect that theThe standard’s disclosure requirements are applied prospectively to all intangible assets as of January 1, 2009. The adoption of this standard will have an immaterialhad no impact on our financial statements.
FSP SFAS 157-2 “Effective Date of FASB Statement No. 157” (SFAS 157-2)
In February 2008, the FASB issued SFAS 157-2 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). As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. In the absence of quoted prices for identical or similar assets or investments in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.
We adopted SFAS 157-2 effective January 1, 2009. We will apply these requirements to applicable fair value measurements which include new asset retirement obligations and impairment analysis related to long-lived assets, equity investments, goodwill and intangibles. We did not record any fair value measurements for nonrecurring nonfinancial assets and liabilities in the first quarter of 2009.
Pronouncements Effective in the Future
The following standards will be effective in the future and their impacts disclosed at that time.
FSP SFAS 107-1 and APB 28-1 “Interim Disclosures about Fair Value of Financial Instruments” (FSP SFAS 107-1 and APB 28-1) |
In April 2009, the FASB issued FSP SFAS 107-1 and APB 28-1 requiring disclosure about the fair value of financial instruments in all interim reporting periods. The standard requires disclosure of the method and significant assumptions used to determine the fair value of financial instruments.
This standard is effective for interim periods ending after June 15, 2009. Management expects this standard to increase the disclosure requirements related to financial instruments. We will adopt the standard effective second quarter of 2009.
FSP SFAS 142-3115-2 and SFAS 124-2 “Recognition and Presentation of Other-Than-Temporary Impairments” (FSP SFAS 115-2 and SFAS 124-2)
In April 2009, the FASB issued FSP SFAS 115-2 and SFAS 124-2 amending the other-than-temporary impairment (OTTI) recognition and measurement guidance for debt securities. For both debt and equity securities, the standard requires disclosure for each interim reporting period of information by security class similar to previous annual disclosure requirements.
This standard is effective January 1,for interim periods ending after June 15, 2009. Management does not expect a material impact as a result of the new OTTI evaluation method for debt securities, but expects this standard to increase the disclosure requirements related to financial instruments. We will adopt the standard effective second quarter of 2009.
FSP FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1)SFAS 132R-1 “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP SFAS 132R-1)
In April 2007,December 2008, the FASB issued FIN 39-1.FSP SFAS 132R-1 providing additional disclosure guidance for pension and OPEB plan assets. The rule requires disclosure of investment policy including target allocations by investment class, investment goals, risk management policies and permitted or prohibited investments. It amendsspecifies a minimum of investment classes by further dividing equity and debt securities by issuer grouping. The standard adds disclosure requirements including hierarchical classes for fair value and concentration of risk.
This standard is effective for fiscal years ending after December 15, 2009. Management expects this standard to increase the disclosure requirements related to our benefit plans. We will adopt the standard effective for the 2009 Annual Report.
FSP SFAS 157-4 “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (FSP SFAS 157-4)
In April 2009, the FASB Interpretation No. 39 “Offsettingissued FSP SFAS 157-4 providing additional guidance on estimating fair value when the volume and level of Amounts Relatedactivity for an asset or liability has significantly decreased, including guidance on identifying circumstances indicating when a transaction is not orderly. Fair value measurements shall be based on the price that would be received to Certain Contracts” by replacingsell an asset or paid to transfer a liability in an orderly (not a distressed sale or forced liquidation) transaction between market participants at the interpretation’s definition of contracts with the definition of derivative instruments per SFAS 133. Itmeasurement date under current market conditions. The standard also requires entities that offsetdisclosures of the inputs and valuation techniques used to measure fair valuesvalue and a discussion 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 derivativeschanges in valuation techniques and related cash collateralinputs, if any, for both interim and amounts recognized for cash collateral payables and receivables at the end of each reporting period.annual periods.
We adopted FIN 39-1 effective January 1, 2008. This standard changedis effective for interim and annual periods ending after June 15, 2009. Management expects this standard to have no impact on our methodfinancial statement but will increase our disclosure requirements. We will adopt the standard effective second quarter of netting certain balance sheet amounts and reduced assets and liabilities. It requires retrospective application as a change in accounting principle. Consequently, we reclassified the following amounts on the December 31, 2007 Condensed Consolidated Balance Sheet as shown:
Balance Sheet Line Description | | As Reported for the December 2007 10-K | | | FIN 39-1 Reclassification | | | As Reported for the September 2008 10-Q | |
Current Assets: | | (in millions) | |
Risk Management Assets | | $ | 286 | | | $ | (15 | ) | | $ | 271 | |
Margin Deposits | | | 58 | | | | (11 | ) | | | 47 | |
Long-term Risk Management Assets | | | 340 | | | | (21 | ) | | | 319 | |
| | | | | | | | | | | | |
Current Liabilities: | | | | | | | | | | | | |
Risk Management Liabilities | | | 250 | | | | (10 | ) | | | 240 | |
Customer Deposits | | | 337 | | | | (36 | ) | | | 301 | |
Long-term Risk Management Liabilities | | | 189 | | | | (1 | ) | | | 188 | |
For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2008 balance sheet, we netted $50 million of cash collateral received from third parties against short-term and long-term risk management assets and $17 million of cash collateral paid to third parties against short-term and long-term risk management liabilities.2009.
Future Accounting Changes
The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued by the FASB, we cannot determine the impact on the reporting of our operations and financial position that may result from any such future changes. The FASB is currently working on several projects including revenue recognition, contingencies, liabilities and equity, emission allowances, earnings per share calculations, leases, insurance, hedge accounting, consolidation policy, discontinued operations, trading inventory and related tax impacts. We also expect to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP. The ultimate pronouncements resulting from these and future projects could have an impact on our future net income and financial position.
EXTRAORDINARY ITEM
In April 2007, Virginia passed legislation to reestablish regulation for retail generation and supply of electricity. As a result, we recorded an extraordinary loss of $118 million ($79 million, net of tax) during the second quarter of 2007 for the reestablishment of regulatory assets and liabilities related to our Virginia retail generation and supply operations. In 2000, we discontinued SFAS 71 regulatory accounting in our Virginia jurisdiction for retail generation and supply operations due to the passage of legislation for customer choice and deregulation.
As discussed in the 20072008 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within our 20072008 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 20082009 and updates the 20072008 Annual Report.
Ohio Rate Matters
Ohio Electric Security Plan Filings
In AprilJuly 2008, as required by the 2008 amendments to 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. A MRO, from the date of its commencement, could transitionlegislation, CSPCo and OPCo to full market rates no sooner than six years and no later than ten years after the PUCO approves a MRO. The PUCO has the authority to approve or modify each utilities’ ESP request. The PUCO is required to approve an ESP if, in the aggregate, the ESP is more favorable to ratepayers than a 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 thefiled ESPs CSPCo and OPCo filed with the PUCO to establish rates for 2009 through 2011.standard service offer rates. CSPCo and OPCo did not file an optional MRO. CSPCoMarket Rate Offer (MRO). CSPCo’s and OPCo eachOPCo’s ESP filings requested an annual rate increase for 2009 through 2011 that would not exceed approximately 15% per year. A significant portion of the requested ESP increases resultsresulted from the implementation of a fuel cost recovery mechanism (which excludes off-system sales)adjustment clause (FAC) 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 inallowances and most other variable production costs. FAC costs were proposed to be phased into customer bills related to the fuel-purchased power cost recovery mechanism would be phased-in over the three yearthree-year period from 2009 through 2011. If the ESP is approved2011 with unrecovered FAC costs to be recorded as filed, effectivea FAC phase-in regulatory asset. The phase-in regulatory asset deferral along with January 2009 billings, CSPCo and OPCo will defer any fuela deferred weighted average cost under-recoveries and relatedof capital carrying costs for future recovery. The under-recoveries and related carrying costs that exist at the end of 2011 willcost was proposed to 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,March 2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s ESPs. The ESPs will be in effect through 2011. The ESP order authorized increases to revenues during the ESP period and capped the overall revenue increases through a findingphase-in of the FAC. The ordered increases for CSPCo are 7% in 2009, 6% in 2010 and order tentatively adopting rules governing MRO6% in 2011 and ESP applications.for OPCo are 8% in 2009, 7% in 2010 and 8% in 2011. After final PUCO review and approval of conforming rate schedules, CSPCo and OPCo filed their ESP applications based on proposed rulesimplemented rates for the April 2009 billing cycle. CSPCo and requested waiversOPCo will collect the 2009 annualized revenue increase over the remainder of 2009.
The order provides a FAC for portionsthe three-year period of the proposed rules.ESP. The PUCO deniedFAC increase will be phased in to meet the waiver requests in September 2008ordered annual caps described above. The FAC increase before phase-in will be subject to quarterly true-ups to actual recoverable FAC costs and orderedto annual accounting audits and prudency reviews. The order allows CSPCo and OPCo to submit information consistent withdefer unrecovered FAC costs resulting from the tentative rules. In October 2008,annual caps/phase-in plan and to accrue carrying charges on such deferrals at CSPCo’s and OPCo’s weighted average cost of capital. The deferred FAC balance at the end of the ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018. As of March 31, 2009, the FAC deferral balances were $17 million and $66 million for CSPCo and OPCo, submitted additional information relatedrespectively, including carrying charges. The PUCO rejected a proposal by several intervenors to proforma financial statements and information concerning CSPCo and OPCo’s fuel procurement process. In October 2008, CSPCo and OPCo filed an applicationoffset the FAC costs with a credit 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.
2008 Generation Rider and Transmission Rider Rate Settlement
On January 30, 2008, the PUCO approved a settlement agreement, among CSPCo, OPCo and other parties, under the additional average 4% generation rate increase and transmission cost recovery rider (TCRR) provisions of the RSP. The increase was to recover additional governmentally-mandated costs including incremental environmental costs. Under the settlement, the PUCO also approved recovery through the TCRR of increased PJM costs associated with transmission line losses of $39 million each for CSPCo and OPCo.off-system sales margins. As a result, CSPCo and OPCo established regulatory assets duringwill retain the first quarterbenefit of 2008their share of $12 millionthe AEP System’s off-system sales. In addition, the ESP order provided for both the FAC deferral credits and $14 million, respectively, relatedthe off-system sales margins to be excluded from the future recovery of increased PJM billings previously expensed from June 2007 to December 2007 for transmission line losses. The PUCO also approved a credit applied to the TCRR of $10 million for OPCo and $8 million for CSPCo for a reduction in PJM net congestion costs. To the extent that collectionsmethodology for the TCRR recoveries are under/over actual netSignificantly Excessive Earnings Test (SEET). The SEET is discussed below.
Additionally, the order addressed several other items, including:
· | The approval of new distribution riders, subject to true-up for recovery of costs for enhanced vegetation management programs, for CSPCo and OPCo and the proposed gridSMART advanced metering initial program roll out in a portion of CSPCo’s service territory. The PUCO proposed that CSPCo mitigate the costs of gridSMART by seeking matching funds under the American Recovery and Reinvestment Act of 2009. As a result, a rider was established to recover 50% or $32 million of the projected $64 million revenue requirement related to gridSMART costs. The PUCO denied the other distribution system reliability programs proposed by CSPCo and OPCo as part of their ESP filings. The PUCO decided that those requests should be examined in the context of a complete distribution base rate case. The order did not require CSPCo and/or OPCo to file a distribution base rate case. |
· | The approval of CSPCo’s and OPCo’s request to recover the incremental carrying costs related to environmental investments made from 2001 through 2008 that are not reflected in existing rates. Future recovery during the ESP period of incremental carrying charges on environmental expenditures incurred beginning in 2009 may be requested in annual filings. |
· | The approval of a $97 million and $55 million increase in CSPCo’s and OPCo’s Provider of Last Resort charges, respectively, to compensate for the risk of customers changing electric suppliers during the ESP period. |
· | The requirement that CSPCo’s and OPCo’s shareholders fund a combined minimum of $15 million in costs over the ESP period for low-income, at-risk customer programs. This funding obligation was recognized as a liability and an unfavorable adjustment to Other Operation and Maintenance expense for the three-month period ending March 31, 2009. |
· | The deferral of CSPCo’s and OPCo’s request to recover certain existing regulatory assets, including customer choice implementation and line extension carrying costs as part of the ESPs. The PUCO decided it would be more appropriate to consider this request in the context of CSPCo’s and OPCo’s next distribution base rate case. These regulatory assets, which were approved by prior PUCO orders, total $58 million for CSPCo and $40 million for OPCo as of March 31, 2009. In addition, CSPCo and OPCo would recover and recognize as income, when collected, $35 million and $26 million, respectively, of related unrecorded equity carrying costs incurred through March 2009. |
Finally, consistent with its decisions on ESP orders of other companies, the PUCO ordered its staff to convene a workshop to determine the methodology for the SEET that will be applicable to all electric utilities in Ohio. The SEET requires the PUCO to determine, following the end of each year of the ESP, if any rate adjustments included in the ESP resulted in excessive earnings as measured by whether the earned return on common equity of CSPCo and OPCo will deferis significantly in excess of the difference as a regulatory asset or regulatory liabilityreturn on common equity that was earned during the same period by publicly traded companies, including utilities, that have comparable business and adjust future customer billingsfinancial risk. If the rate adjustments, in the aggregate, result in significantly excessive earnings in comparison, the PUCO must require that the amount of the excess be returned to reflect actual costs, including carrying costscustomers. The PUCO’s decision on the deferral. UnderSEET review of CSPCo’s and OPCo’s 2009 earnings is not expected to be finalized until the termssecond or third quarter of the settlement, although the increased PJM costs associated with transmission line losses will be recovered through the TCRR, these recoveries will still be applied to reduce the annual average 4% generation rate increase limitation. In addition, the PUCO approved recoveries through generation rates of environmental costs and related carrying costs of $29 million for CSPCo and $5 million for OPCo. These RSP rate adjustments were implemented in February 2008.2010.
Also, in February 2008, Ormet, a major industrial customer,In March 2009, intervenors filed a motion to intervenestay a portion of the ESP rates or alternately make that portion subject to refund because the intervenors believed that the ordered ESP rates for 2009 were retroactive and an application fortherefore unlawful. In March 2009, the PUCO approved CSPCo’s and OPCo’s tariffs effective with the April 2009 billing cycle and rejected the intervenors’ motion. The PUCO also clarified that the reference in its earlier order to the January 1, 2009 date related to the term of the ESP, not to the effective date of tariffs and clarified the tariffs were not retroactive. In March 2009, CSPCo and OPCo implemented the new ESP tariffs effective with the start of the April 2009 billing cycle. In April 2009, CSPCo and OPCo filed a motion requesting rehearing of several issues. In April 2009, several intervenors filed motions requesting rehearing of issues underlying the PUCO’s January 2008 RSP order claiming the settlement inappropriately shifted $4 million in cost recovery to Ormet. In March 2008,authorized rate increases and one intervenor filed a motion requesting the PUCO granted Ormet’s motion to intervene. Ormet’s rehearing applicationdirect CSPCo and OPCo to cease collecting rates under the order. Certain intervenors also was grantedfiled a complaint for writ of prohibition with the purposeOhio Supreme Court to halt any further collection from customers of providingwhat the PUCO with additional time to consider the issues raised by Ormet. Upon PUCO approval of an unrelated amendment to the Ormet contract, Ormet withdrew its rehearing application in August 2008.intervenors claim is unlawful retroactive rate increases.
Management will evaluate whether it will withdraw the ESP applications after a final order, thereby terminating the ESP proceedings. If CSPCo and/or OPCo withdraw the ESP applications, CSPCo and/or OPCo may file an MRO or another ESP as permitted by the law. The revenues collected and recorded in 2009 under this PUCO order are subject to possible refund through the SEET process. Management is unable, due to the decision of the PUCO to defer guidance on the SEET methodology to a future generic SEET proceeding, to estimate the amount, if any, of a possible refund that could result from the SEET process in 2010.
Ohio IGCC Plant
In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs related to building and operating a 629 MW IGCC power plant using clean-coal technology. The application proposed three phases of cost recovery associated with the IGCC plant: Phase 1, recovery of $24 million in pre-construction costs; Phase 2, concurrent recovery of construction-financing costs; and Phase 3, recovery or refund in distribution rates of any difference between the generation rates which may be a market-based standard service offer price for generation and the expected higher cost of operating and maintaining the plant, including a return on and return of the projected cost to construct the plant.
In June 2006, the PUCO issued an order approving a tariff to allow CSPCo and OPCo to recover Phase 1 pre-construction costs over a period of no more than twelve months effective July 1, 2006. During that period, CSPCo and OPCo each collected $12 million in pre-construction costs and incurred $11 million in pre-construction costs. As a result, CSPCo and OPCo each established a net regulatory liability of approximately $1 million.
The order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant within five years of the June 2006 PUCO order, all Phase 1pre-construction cost recoveries associated with items that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest. The PUCO deferred ruling on cost recovery for Phases 2 and 3 pending further hearings.
In August 2006, intervenors filed four separate appeals of the PUCO’s order in the IGCC proceeding. In March 2008, the Ohio Supreme Court issued its opinion affirming in part, and reversing in part the PUCO’s order and remanded the matter back to the PUCO. The Ohio Supreme Court held that while there could be an opportunity under existing law to recover a portion of the IGCC costs in distribution rates, traditional rate making procedures would apply to the recoverable portion. The Ohio Supreme Court did not address the matter of refunding the Phase 1 cost recovery and declined to create an exception to its precedent of denying claims for refund of past recoveries from approved orders of the PUCO. In September 2008, the Ohio Consumers’ Counsel filed a motion with the PUCO requesting all Phase 1pre-construction costs be refunded to Ohio ratepayers with interest because the Ohio Supreme Court invalidated the underlying foundation for the Phase 1 recovery.interest. In October 2008, CSPCo and OPCo filed a motion with the PUCO that argued the Ohio Consumers’ Counsel’s motion was without legal merit and contrary to past precedent.
In January 2009, a PUCO Attorney Examiner issued an order that CSPCo and OPCo file a detailed statement outlining the status of the construction of the IGCC plant, including whether CSPCo and OPCo are engaged in a continuous course of construction on the IGCC plant. In February 2009, CSPCo and OPCo filed a statement that CSPCo and OPCo have not commenced construction of the IGCC plant and believe there exist real statutory barriers to the construction of any new base load generation in Ohio, including IGCC plants. The statement also indicated that while construction on the IGCC plant might not begin by June 2011, changes in circumstances could result in the commencement of construction on a continuous course by that time.
Management continues to pursue the ultimate construction of the IGCC plant. However, CSPCo and OPCo will not start construction of the IGCC plant until sufficient assurance of regulatory cost recovery exists. If CSPCo and OPCo were required to refund the $24 million collected 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.
As Management cannot predict the outcome of December 31, 2007, the cost ofrecovery litigation concerning the plant was estimated at $2.7 billion. The estimated cost of the plant has continued to increase significantly. Management continues to pursue the ultimate construction of the IGCC plant. CSPCo and OPCo will not start construction of theOhio IGCC plant until sufficient assurance of regulatory cost recovery exists.or what, if any effect, the litigation will have on future net income and cash flows.
Ormet
EffectiveIn December 2008, CSPCo, OPCo and Ormet, a large aluminum company with a load of 520 MW, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet. The arrangement would be effective January 1, 2007, CSPCo2009 and remain in effect and expire upon the effective date of CSPCo’s and OPCo’s new ESP rates and the effective date of a new arrangement between Ormet and CSPCo/OPCo began to serve Ormet, a major industrial customer with a 520 MW load, in accordance with a settlement agreementas approved by the PUCO. The settlement agreement allows forUnder the recoveryinterim arrangement, Ormet would pay the then-current applicable generation tariff rates and riders. CSPCo and OPCo sought to defer as a regulatory asset beginning in 2007 and 2008 of2009 the difference between the $43 per MWH Ormet pays for power and a PUCO-approved market price, if higher. The PUCO approved a $47.69 per MWH market price for 2007 and the difference was recovered through the amortization of a $57 million ($15 million for CSPCo and $42 million for OPCo) excess deferred tax regulatory liability resulting from an Ohio franchise tax phase-out recorded in 2005.
CSPCo and OPCo each amortized $8 million of this regulatory liability to income for the nine months ended September 30, 2008 based on the previously approved 2007 price of $47.69 per MWH. In December 2007, CSPCo and OPCo submitted for approval a market price of $53.03 per MWH for 2008. The PUCO has not yet approvedand the 2008 market price. If the PUCO approves a market price for 2008 below $47.69, it could have an adverse effect on future net incomeapplicable generation tariff rates and cash flows. A price above $47.69 should result in a favorable effect. Ifriders. CSPCo and OPCo serveproposed to recover the deferral through the fuel adjustment clause mechanism they proposed in the ESP proceeding. In January 2009, the PUCO approved the application as an interim arrangement. In February 2009, an intervenor filed an application for rehearing of the PUCO’s interim arrangement approval. In March 2009, the PUCO granted that application for further consideration of the matters specified in the rehearing application.
In February 2009, as amended in April 2009, Ormet filed an application with the PUCO for approval of a proposed Ormet power contract for 2009 through 2018. Ormet proposed to pay varying amounts based on certain conditions, including the price of aluminum and the level of production. The difference between the amounts paid by Ormet and the otherwise applicable PUCO ESP tariff rate would be either collected from or refunded to CSPCo’s and OPCo’s retail customers.
In March 2009, the PUCO issued an order in the ESP filings which included approval of a FAC for the ESP period. The approval of an ESP FAC, together with the January 2009 PUCO approval of the Ormet load after 2008 without any special provisions, they could experience incremental costsinterim arrangement, provided the basis to acquire additional capacity to meet their reserve requirements and/or forgo more profitable market-priced off-system sales.record regulatory assets of $10 million and $9 million for CSPCo and OPCo, respectively, for the differential in the approved market price of $53.03 versus the rate paid by Ormet during the first quarter of 2009. These amounts are included in CSPCo’s and OPCo’s FAC phase-in deferral balance of $17 million and $66 million, respectively. See “Ohio Electric Security Plan Filings” section above.
The pricing and deferral authority under the PUCO’s January 2009 approval of the interim arrangement will continue until the 2009-2018 power contract becomes effective. Management cannot predict when or if the PUCO will approve the new power contract.
Hurricane Ike
In September 2008, the service territories of CSPCo and OPCo were impacted by strong winds from the remnants of Hurricane Ike. Under the RSP, which was effective in 2008, CSPCo and OPCo incurred approximately $18 million and $13 million, respectively, in incremental distribution operation and maintenance costs related to service restoration efforts. Under the current RSP, CSPCo and OPCo cancould seek a distribution rate adjustment to recover incremental distribution expenses related to major storm service restoration efforts. In September 2008, CSPCo and OPCo established regulatory assets of $17 million and $10 million, respectively, for the incremental distribution operationexpected recovery of the storm restoration costs. In December 2008, CSPCo and maintenance costs relatedOPCo filed with the PUCO a request to service restoration efforts. Theestablish the regulatory assets representunder the excess above the averageterms of the last three yearsRSP, plus accrue carrying costs on the unrecovered balance using CSPCo’s and OPCo’s weighted average cost of capital carrying charge rates. In December 2008, the PUCO subsequently approved the establishment of the regulatory assets but authorized CSPCo and OPCo to record a long-term debt only carrying cost on the regulatory asset. In its order approving the deferrals, the PUCO stated that the mechanism for recovery would be determined in CSPCo’s and OPCo’s next distribution storm expenses excluding Hurricane Ike, which wasrate filing.
In December 2008, the methodology usedConsumers for Reliable Electricity in Ohio filed a request with the PUCO asking for an investigation into the service reliability of Ohio’s investor-owned electric utilities, including CSPCo and OPCo. The investigation request included the widespread outages caused by the September 2008 wind storm. CSPCo and OPCo filed a response asking the PUCO to determinedeny the recoverable amount of storm restoration expenses in the most recent 2006 PUCO storm damage recovery decision. Prior to December 31, 2008, which is the expiration of the RSP, CSPCo and OPCo will file for recovery of the regulatory assets. request.
As a result of the past favorable treatment of storm restoration costs under the RSP and the favorable RSP recovery provisions, which were in effect when the storm occurred and the filings made, management believes the recovery of the regulatory assets is probable. IfHowever, if these regulatory assets are not recoverable,recovered, it would have an adverse effect on future net income and cash flows.
Texas Rate Matters
TEXAS RESTRUCTURING
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 inthrough the end of 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 paidAlthough earnings were not affected by this CTC refund, cash flow was adversely impacted for these CTC refunds for the nine months ended September 30, 2008, 2007 and 2007 was2006 by $75 million, $238 million and $207$69 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. The significant items appealed by TCC are:were:
· | The PUCT ruling that TCC did not comply with the Texas Restructuring Legislation and PUCT rules regarding the required auction of 15% of its Texas jurisdictional installed capacity, which led to a significant disallowance of capacity auction true-up revenues. |
· | The PUCT ruling that TCC acted in a manner that was commercially unreasonable, because TCC failed to determine a minimum price at which it would reject bids for the sale of its nuclear generating plant and TCC bundled out-of-the-money gas units with the sale of its coal unit, which led to the disallowance of a significant portion of TCC’s net stranded generation plant costs. |
· | Two federal matters regarding the allocation of off-system sales related to fuel recoveries and a potential tax normalization violation. |
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. This remand could potentially have an adverse effect on TCC’s future net income and cash flows if upheld on appeal. The District Court judge also determined that the PUCT improperly reduced TCC’s net stranded plant costs for commercial unreasonableness.unreasonableness which could have a favorable effect on TCC’s future net income and cash flows.
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 onetwo major respect.respects. It reversed the District Court’s unfavorable decision findingwhich found that the PUCT erred by applying an invalid rule to determine the carrying cost rate. It also determined that the PUCT erred by not reducing stranded costs by the “excess earnings” that had already been refunded to affiliated REPs. Management does not believe that TCC will be adversely affected by the Court of Appeals ruling on excess earnings based upon the reasons discussed in the “TCC Excess Earnings” section below. The favorable commercial unreasonableness decisionjudgment entered by the District Court 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. Review is discretionary and the Texas Supreme Court has not determined if it will grant review. In January 2009, the Texas Supreme Court requested full briefing of the proceedings.
TNC received its final true-up order in May 2005 that resulted in refunds via a CTC which have been completed. The appeal brought by TNC of the final true-up order remains pending in state court.
Management cannot predict the outcome of these court proceedings and PUCT remand decisions. If TCC and/or TNC ultimately succeedssucceed in itstheir 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 substantialmaterial adverse effect on future net income, cash flows and possibly financial condition.
TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes
Appeals remainTCC’s appeal remains outstanding related to the stranded costs true-up and related orders regarding whether the PUCT may require TCC to refund certain tax benefits to customers. TheSubsequent to the PUCT’s ordered reduction to TCC’s securitized stranded costs by certain tax benefits, the PUCT, agreedreacting to allowpossible IRS normalization violations, allowed TCC to defer $103 million of theordered CTC refunds for other true-up items to refundnegate the securitization reduction. Of the $103 million, $61 million relates to customers ($61 million inthe present value of thecertain tax benefits associated with TCC’s generationapplied to reduce the securitization stranded generating assets plusand $42 million offor related carrying costs)costs. The deferral of the CTC refunds is pending resolution ofon whether the PUCT’s securitization refund is an IRS normalization violation. The deferral
Evidence supporting a possible IRS normalization violation includes a March 2008 IRS issuance of the CTC refund negates the securitization reduction pending resolution offinal regulations addressing the normalization violation issue.
In March 2008,requirements for the IRS issued final regulations addressingtreatment of Accumulated Deferred Investment Tax Credit (ADITC) and Excess Deferred Federal Income Tax (EDFIT) normalization requirements.in a stranded cost determination. Consistent with a Private Letter Ruling TCC received in 2006, the final regulations clearly state that TCC will sustain a normalization violation if the PUCT orders TCC to flow the tax benefits to customers.customers as part of the stranded cost true-up. TCC notified the PUCT that the final regulations were issued. The PUCT made a request to the Texas Court of Appeals for the matter to be remanded back to the PUCT for further action. In May 2008, as requested by the PUCT, the Texas Court of Appeals ordered a remand of the tax normalization issue for the consideration of this additional evidence.
TCC expects that the PUCT will allow TCC to retain and not refund these amounts. This will have a favorable effect on future net income and cash flows as TCC will recordbe free to amortize the deferred ADITC and EDFIT tax benefits into income due to the sale of the generating plants that generated the tax benefits. Since management expects that the PUCT will allow TCC to retain the deferred CTC refund amounts in order to avoid an IRS normalization violation, management has not accrued any related interest expense should TCC ultimately be required to refundfor refunds of these amounts. If accrued, management estimates the interest expense would behave been approximately $2$6 million higher for the period July 1, 2008 through September 30, 2008March 2009 based on a CTC interest rate of 7.5%. with $4 million relating to 2008.
However, ifIf the PUCT orders TCC to flowreturn the tax benefits to customers, thereby causing TCC to violatea violation of the IRS’IRS normalization regulations, itthe violation could result in TCC’s repayment to the IRS, under the normalization rules, of ADITC on all property, including transmission and distribution property. This amount approximates $103 million as of September 30, 2008.March 31, 2009. It willcould also lead to a loss of TCC’s right to claim accelerated tax depreciation in future tax returns. If TCC is required to repay to the IRS its ADITC and is also required to refund ADITC to customers, it would have an unfavorable effect on future net income and cash flows. Tax counsel advised management that a normalization violation should not occur until all remedies under law have been exhausted and the tax benefits are actually returned to ratepayers under a nonappealable order. Management intends to continue to work with the PUCT to favorably resolve the issue and avoid the adverse effects of a normalization violation on future net income, cash flows and financial condition.
TCC Excess Earnings
In 2005, a Texas appellate court issued a decision finding that a PUCT order requiring TCC to refund to the REPs excess earnings prior to and outside of the true-up process was unlawful under the Texas Restructuring Legislation. From 2002 to 2005, TCC refunded $55 million of excess earnings, including interest, under the overturned PUCT order. On remand, the PUCT must determine how to implement the Court of Appeals decision given that the unauthorized refunds were made to the REPs in lieu of reducing stranded cost recoveries from REPs in the True-up Proceeding. It is possible that TCC’s stranded cost recovery, which is currently on appeal, may be affected by a PUCT remedy.
In May 2008, the Texas Court of Appeals issued a decision in TCC’s True-up Proceeding determining that even though excess earnings had been previously refunded to REPs, TCC still must reduce stranded cost recoveries in its True-up Proceeding. In 2005, TCC reflected the obligation to refund excess earnings to customers through the true-up process and recorded a regulatory asset of $55 million representing a receivable from the REPs for prior excess earnings refunds made to them by TCC. However, certain parties have taken positions that, if adopted, could result in TCC being required to refund additional amounts of excess earnings or interest through the true-up process without receiving a refund back from the REPs. If this were to occur, it would have an adverse effect on future net income and cash flows. AEP sold its affiliate REPs in December 2002. While AEP owned the affiliate REPs, TCC refunded $11 million of excess earnings to the affiliate REPs. Management cannot predict the outcome of the excess earnings remand and whether it will adversely affectwould have an adverse effect on future net income and cash flows.
Texas Restructuring – SPP
In August 2006, the PUCT adopted a rule extending the delay in implementation of customer choice in SWEPCo’s SPP area of Texas until no sooner than January 1, 2011. In April 2009, the Texas Senate passed a bill related to SWEPCo’s SPP area of Texas that requires cost of service regulation until certain stages have been completed and approved by the PUCT such that fair competition is available to all retail customer classes. The bill is expected to be reviewed by the Texas House of Representatives which, if passed, would be sent to the governor of Texas for approval. If the bill is signed, management may be required to re-apply SFAS 71 for the generation portion of SWEPCo’s Texas jurisdiction. The initial reapplication of SFAS 71 regulatory accounting would likely result in an extraordinary loss.
OTHER TEXAS RATE MATTERS
Hurricanes Dolly and Ike
In July and September 2008, TCC’s service territory in south Texas was hit by Hurricanes Dolly and Ike, respectively. TCC incurred $11$23 million and $1$2 million in incremental operation and maintenance costs related to service restoration efforts for Hurricanes Dolly and Ike, respectively. TCC has a PUCT-approved catastrophe reserve which permits TCC to collect $1.3 million on an annual basisannually with authority to continue the collection until the catastrophe reserve reaches $13 million. Any incremental operation andstorm-related maintenance costs can be charged against the catastrophe reserve if the total incremental operation and maintenance costs for a storm exceed $500 thousand. In June 2008, prior to these hurricanes, TCC had approximately $2 million recorded in the catastrophe reserve account. Since the catastrophe reserve balance was less than the incremental operation and maintenance costs related to Hurricanes Dolly and Ike,Therefore, TCC established a net regulatory asset for $10$23 million.
Under Texas law and as previously approved by the PUCT in prior base rate cases, the regulatory asset will be included in rate base in the next base rate filing. At that time, TCC will evaluate the existing catastrophe reserve amounts and review potential future events to determine the appropriate funding level to request.request to both recover the regulatory asset and adequately fund a reserve for future storms in a reasonable time period.
2008 Interim Transmission Rates
In March 2008, TCC and TNC filed applications with the PUCT for an interim update of wholesale-transmission rates. The PUCT issued an order in May 2008 that provided for increased interim transmission rates for TCC and TNC, subject to review during the next TCC and TNC base rate case. This review could result in a refund if the PUCT finds that TCC and TNC have not prudently incurred the transmission investment. The FERC approved the new interim transmission rates in May 2008 which increased annual transmission revenues by $9 million and $4 million for TCC and TNC, respectively. TCC and TNC have not recorded any provision for refund regarding the interim transmission rates because management believes these new rates are reasonable and necessary to recover costs associated with new transmission plant. Management cannot predict the outcome of future proceedings related to the interim transmission rates. A refund of the interim transmission rates would have an adverse impact on net income and cash flows.
2009 Interim Transmission Rates
In February 2009, TCC and TNC filed applications with the PUCT for an interim update of wholesale-transmission rates. The proposed new interim transmission rates are estimated to increase annual transmission revenues by $8 million and $9 million for TCC and TNC, respectively. In April 2009, the PUCT staff recommended the applications be approved as filed. A decision is expected from the PUCT during the second quarter of 2009 with rates increasing shortly thereafter upon the FERC’s concurrence. Management cannot predict the outcome of the interim transmission rates proceeding.
Advanced Metering System
In 2007, the governor of Texas signed legislation directing the PUCT to establish a surcharge for electric utilities relating to advanced meters. In April 2009, TCC and TNC filed their Advanced Metering System (AMS) with the PUCT proposing to invest approximately $223 million and $61 million, respectively, to be recovered through customer surcharges beginning in October 2009. The TCC and TNC filing is modeled on similar filings by other Texas ERCOT Investor Owned Utilities who have already received PUCT approval for their plans. In the filing TCC and TNC propose to apply customer refunds related to the FERC SIA ruling to reduce the AMS investment and associated customer surcharge. As of March 31, 2009, TCC and TNC has $2.8 million and $0.5 million recorded on their balance sheets related to advanced meters.
Texas Rate Filing
In November 2006, TCC filed a base rate case seeking to increase transmission and distribution energy delivery services (wires) base rate in Texas. TCC’s revised requested increase in annual base rates was $70 million based on a requested return on common equity of 10.75%.
TCC implemented the rate change in June 2007, subject to refund. In March 2008, the PUCT issued an order approving rates to collect a $20 million base rate increase based on a return on common equity of 9.96% and an additional $20 million increase in revenues related to the expiration of TCC’s merger credits. In addition, depreciation expense was decreased by $7 million and discretionary fee revenues were increased by $3 million. TCC estimates the order will increase TCC’s annual pretax income by $50 million. Various parties appealed the PUCT decision.
In February 2009, the Texas District Court affirmed the PUCT in most respects. However, it also ruled that the PUCT improperly denied TCC an AFUDC return on the prepaid pension asset that the PUCT ruled to be CWIP. In March 2009, various intervenors appealed the Texas District Court decision to the Texas Court of Appeals. Management is unable to predict the outcome of these proceedings. If the appeals are successful, it could have an adverse effect on future net income and cash flows.
ETT
In December 2007, TCC contributed $70 million of transmission facilities to ETT, a newly-formedan AEP joint venture which will own and operate transmission assets in ERCOT.accounted for using the equity method. The PUCT approved ETT's initial rates, itsa request for a transfer of facilities and a certificate of convenience and necessity to operate as a stand alone transmission utility in the ERCOT region. ETT was awardedallowed a 9.96% after tax return on equity rate in those approvals. In 2008, intervenors filed a notice of appeal to the Travis County District Court. In October 2008, the court ruled that the PUCT exceeded its authority by approving ETT’s application as a stand alone transmission utility without a service area under the wrong section of the statute. Management believes that ruling is incorrect. Moreover, ETT provided evidence in its application that ETT has complied with what the court determined was the proper section of the statute. In January 2009, ETT and the PUCT filed appeals to the Texas Court of Appeals. In January and April 2009, TCC sold $60 million and $30 million, respectively, of additional transmission facilities to ETT. As of September 30, 2008,March 31, 2009, AEP’s net investment in ETT was $16$36 million. ETT is considering its options for responding to the ruling including an appeal of the Travis County District Court ruling. Depending upon the ultimate outcome of the Travis County District Court ruling,appeals and any resulting remands, TCC may be required to repurchasereacquire transferred assets and projects under construction by ETT.
ETT, TCC and TNC are involved in transactions relating to the $70transfer to ETT of other transmission assets, which are in various stages of review and approval. In September 2008, ETT and a group of other Texas transmission providers filed a comprehensive plan with the PUCT for completion of the Competitive Renewable Energy Zone (CREZ) initiative. The CREZ initiative is the development of 2,400 miles of new transmission lines to transport electricity from 18,000 MWs of planned wind farm capacity in west Texas to rapidly growing cities in eastern Texas. In March 2009, the PUCT issued an order pursuant to a January 2009 decision that authorized ETT to pursue the construction of $841 million of new CREZ transmission facilities TCC contributed to ETT. Management cannot predict the outcome of this proceeding or its future effect on net income and cash flows.assets.
Stall Unit
See “Stall Unit” section within the Louisiana“Louisiana Rate MattersMatters” for disclosure.
Turk Plant
See “Turk Plant” section within the Arkansas“Arkansas Rate MattersMatters” for disclosure.
Virginia Rate Matters
Virginia Base Rate Filing
In May 2008, APCo filed an application with the Virginia SCC to increase its base rates by $208 million on an annual basis. The requested increase is based upon a calendar 2007 test year adjusted for changes in revenues, expenses, rate base and capital structure through June 2008. This is consistent with the ratemaking treatment adopted by the Virginia SCC in APCo’s 2006 base rate case. The proposed revenue requirement reflects a return on equity of 11.75%. Hearings began in October 2008. As permitted under Virginia law, APCo implemented these new base rates, subject to refund, effective October 28, 2008.
In September 2008, the Attorney General’s office filed testimony recommending the proposed $208 million annual increase in base rate be reduced to $133 million. The decrease is principally due to the use of a return on equity approved in the last base rate case of 10% and various rate base and operating income adjustments, including a $25 million proposed disallowance of capacity equalization charges payable by APCo as a deficit member of the FERC approved AEP Power Pool.
In October 2008, the Virginia SCC staff filed testimony recommending the proposed $208 million annual increase in base rate be reduced to $157 million. The decrease is principally due to the use of a recommended return on equity of 10.1%. In October 2008, hearings were held in which APCo filed a $168 million settlement agreement which was accepted by all parties except one industrial customer. APCo expects to receive a final order from the Virginia SCC in November 2008.
Virginia E&R Costs Recovery Filing
As of September 2008,Due to the recovery provisions in Virginia law, APCo has $118 million of deferred Virginiabeen deferring incremental E&R costs (excluding $25 million of unrecognizedas incurred, excluding the equity carrying costs). The $118 million consists of $6 million already approved by the Virginia SCC to be collected during the fourth quarter 2008, $54 million relating to APCo’s May 2008 filing for recovery in 2009, and $58 million, representing costs deferred in 2008 to date, to be included (along with the fourth quarter 2008 E&R deferrals) in the 2009 E&R filing, to be collected in 2010.
In September 2008, a settlement was reached between the parties to the 2008 filing and a stipulation agreement (stipulation) was submitted to the hearing examiner. The stipulation provides for recovery of $61 million of incremental E&R costs in 2009 which is an increase of $12 million over the level of E&R surcharge revenues being collected in 2008. The stipulation included an unfavorable $1 million adjustment related to certain costs considered not recoverable E&R costs and recovery of $4.5 million representing one-half of a $9 million Virginia jurisdictional portion of NSR settlement expenses recorded in 2007. In accordance with the stipulation, APCo will request the remaining one-half of the $9 million of NSR settlement expenses in APCo’s 2009 E&R filing. The stipulation also specifies that APCo will remove $3 million of the $9 million of NSR settlement expenses requested to be recovered over 3 years in the current base rate case from the base rate case’s revenue requirement.
In September 2008, the hearing examiner recommended that the Virginia SCC accept the stipulation. As a result, in September 2008, APCo deferred as a regulatory asset $9 million of NSR settlement expenses it had expensed in 2007 that have become probable ofreturn on non-CWIP capital investments, pending future recovery. In October 2008, the Virginia SCC approved thea stipulation agreement to recover $61 million of incremental E&R costs incurred from October 2006 to December 2007 through a surcharge in 2009 which will have a favorable effect on 2009 future cash flows of $61 million and on net income for the previously unrecognized equity portion of the carrying costs of approximately $11 million.
The Virginia E&R cost recovery mechanism under Virginia law ceased effective with costs incurred through December 2008. However, the 2007 amendments to Virginia’s electric utility restructuring law provide for a rate adjustment clause to be requested in 2009 to recover incremental E&R costs incurred through December 2008. Under this amendment, APCo will request recovery of its 2008 unrecovered incremental E&R costs in a planned May 2009 filing. As of March 31, 2009, APCo has $109 million of deferred Virginia incremental E&R costs (excluding $22 million of unrecognized equity carrying costs). The $109 million consists of $6 million of over recovery of costs collected from the 2008 surcharge, $36 million approved by the Virginia SCC related to the 2009 surcharge and $79 million, representing costs deferred during 2008, to be included in the 2009 E&R filing, for collection in 2010.
If the Virginia SCC were to disallow a material portion of APCo’s 2008 deferral,deferred incremental E&R costs, it would have an adverse effect on future net income and cash flows.
Virginia Fuel ClauseAPCo’s Filings for an IGCC Plant
In July 2007,January 2006, APCo filed an application witha petition from the Virginia SCCWVPSC requesting approval of a Certificate of Public Convenience and Necessity (CPCN) to seek an annualized increase, effective September 1, 2007, of $33 million for fuel costs and sharing of off-system sales.construct a 629 MW IGCC plant adjacent to APCo’s existing Mountaineer Generating Station in Mason County, West Virginia.
In FebruaryJune 2007, APCo sought pre-approval from the WVPSC for a surcharge rate mechanism to provide for the timely recovery of pre-construction costs and the ongoing finance costs of the project during the construction period, as well as the capital costs, operating costs and a return on equity once the facility is placed into commercial operation. In March 2008, the Virginia SCC issued an order thatWVPSC granted APCo the CPCN to build the plant and approved a reduced fuel factor effectivethe requested cost recovery. In March 2008, various intervenors filed petitions with the February 2008 billing cycle. The order terminatedWVPSC to reconsider the off-system sales margin rider and approved a 75%-25% sharing of off-system sales margins between customers and APCo effective September 1, 2007 as required byorder. No action has been taken on the re-regulation legislation in Virginia. The order also allows APCo to include in its monthly under/over recovery deferrals the Virginia jurisdictional share of PJM transmission line loss costs from June 2007. The adjusted factor increases annual fuel clause revenues by $4 million. The order authorized the Virginia SCC staff and other parties to make specific recommendations to the Virginia SCC in APCo’s next fuel factor proceeding to ensure accurate assignment of the prudently incurred PJM transmission line loss costs to APCo’s Virginia jurisdictional operations. Management believes the incurred PJM transmission line loss costs are prudently incurred and are being properly assigned to APCo’s Virginia jurisdictional operations.
In July 2008, APCo filed its next fuel factor proceeding with the Virginia SCC and requested an annualized increase of $132 million effective September 1, 2008. The increase primarily relates to increases in coal costs. In August 2008, the Virginia SCC issued an order to allow APCo to implement the increased fuel factor on an interim basisrequests for services rendered after August 2008. In September 2008, the Virginia SCC staff filed testimony recommending a lower fuel factor which will result in an annualized increase of $117 million, which includes the PJM transmission line loss costs, instead of APCo’s proposed $132 million. In October 2008, the Virginia SCC ordered an annualized increase of $117 million for services rendered on and after October 20, 2008.
APCo’s Virginia SCC Filing for an IGCC Plantrehearing.
In July 2007, APCo filed a request with the Virginia SCC for a rate adjustment clause to recover initial costs associated with a proposed 629 MW IGCC plant to be constructed in Mason County, West Virginia adjacent to APCo’s existing Mountaineer Generating Station for an estimated cost of $2.2 billion.plant. The filing requested recovery of an estimated $45 million over twelve months beginning January 1, 2009 including2009. The $45 million included a return on projected CWIP and development, design and planning pre-construction costs incurred from July 1, 2007 through December 31, 2009. APCo also requested authorization to defer a returncarrying cost on deferred pre-construction costs incurred beginning July 1, 2007 until such costs are recovered. Through September 30, 2008, APCo has deferred for future recovery pre-construction IGCC costs of approximately $9 million allocated to Virginia jurisdictional operations.
The Virginia SCC issued an order in April 2008 denying APCo’s requests, stating the beliefin part, upon its finding that the estimated cost of the plant was uncertain and may be significantly understated.escalate. The Virginia SCC also expressed concern that the $2.2 billion estimated cost did not include a retrofitting of carbon capture and sequestration facilities. In AprilJuly 2008, based on the unfavorable order received in Virginia, the WVPSC issued a notice seeking comments from parties on how the WVPSC should proceed. Various parties, including APCo, filed a petitioncomments but the WVPSC has not taken any action.
Through March 31, 2009, APCo deferred for reconsideration in Virginia. In May 2008, thefuture recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia SCC denied APCo’s requestjurisdiction, approximately $2 million applicable to reconsider its previous ruling. FERC jurisdiction and approximately $9 million allocated to its Virginia jurisdiction.
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 expenseexpenses being incurred and certification of the IGCC plant prior to July 2010.
Although management continues to pursue the construction of the IGCC plant, APCo will not start construction of the IGCC plant until sufficient assurance of cost recovery exists. If the 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.
Mountaineer Carbon Capture Project
In January 2008, APCo and ALSTOM Power Inc. (Alstom), an unrelated third party, entered into an agreement to jointly construct a CO2 capture demonstration facility. APCo and Alstom will each own part of the CO2 capture facility. APCo will also construct and own the necessary facilities to store the CO2. RWE AG, a German electric power and natural gas public utility, is participating in the project and is providing some funding to offset APCo's costs. APCo’s estimated cost for its share of the facilities is $76$73 million. Through September 30, 2008,March 31, 2009, APCo incurred $13$45 million in capitalized project costs which isare included in Regulatory Assets. APCo earns a return on the capitalized project costs incurred through June 30, 2008, as a result of the base rate case settlement approved by the Virginia SCC in November 2008. APCo plans to seek recovery for the CO2 capture and storage project costs including a return on the additional investment since June 2008 in its next Virginia and West Virginia base rate filings which are expected to be filed in 2009. APCo is presently seeking a return on the capitalized project costs in its current Virginia base rate filing. The Attorney General has recommended that the project costs should be shared by all affiliated operating companies with coal-fired generation plants. If a significant portion of the deferred project costs are excluded from base rates and ultimately disallowed in future Virginia and/or West Virginia rate proceedings, it could have an adverse effect on future net income and cash flows.
West Virginia Rate Matters
APCo’s and WPCo’s 20082009 Expanded Net Energy Cost (ENEC) Filing
In February 2008,March 2009, APCo and WPCo filed an annual ENEC filing with the WVPSC for an increase of approximately $156$442 million including a $135 million increase in the ENEC, a $17 million increase in construction cost surchargesfor incremental fuel, purchased power and $4 million of reliability expenditures,environmental compliance project expenses, to become effective July 2008. 2009. Within the filing, APCo and WPCo requested the WVPSC to allow APCo and WPCo to temporarily adopt a modified ENEC mechanism due to the distressed economy. The proposed modified ENEC mechanism provides that all deferred ENEC amounts as of June 30, 2009 be recovered over a five-year period beginning in July 2009. The mechanism also extends cost projections out for a period of three years through June 30, 2012 and provides for three annual increases to recover projected future ENEC cost increases. APCo and WPCo are also requesting all deferred amounts that exceed the deferred amounts that would have existed under the traditional ENEC mechanism be subject to a carrying charge based upon APCo’s and WPCo’s weighted average cost of capital. As filed, the modified ENEC mechanism would produce three annual increases, including carrying charges, of $189 million, $166 million and $172 million, effective July 2009, 2010 and 2011, respectively.
In June 2008,March 2009, the WVPSC issued an order approvingsuspending the rate increase request until December 2009. In April 2009, APCo and WPCo filed a joint stipulation and settlement agreement grantingmotion for approval of an interim rate increases,increase of $180 million, effective July 2008,2009 and subject to refund pending the final adjudication of approximately $106 million, including an $88 million increase in the ENEC a $14 million increase in construction cost surcharges and $4 million of reliability expenditures. The ENEC is an expanded form of fuel clause mechanism, which includes all energy-related costs including fuel, purchased power expenses, off-system sales credits, PJM costs associated with transmission line losses due to the implementation of marginal loss pricing and other energy/transmission items.
The ENEC is subject to a true-up to actual costs and should have no earnings effect if actual costs exceed the recoveries due to the deferral of any over/under-recovery of ENEC costs. The construction cost and reliability surcharges are not subject to a true-up to actual costs and could impact future net income and cash flows.
APCo’s West Virginia IGCC Plant Filing
by December 2009. In January 2006, APCo filed a petition with the WVPSC requesting its approval of a Certificate of Public Convenience and Necessity (CCN) to construct a 629 MW IGCC plant adjacent to APCo’s existing Mountaineer Generating Station in Mason County, West Virginia.
In June 2007, APCo filed testimony with the WVPSC supporting the requests for a CCN and for pre-approval of a surcharge rate mechanism to provide for the timely recovery of both pre-construction costs and the ongoing finance costs of the project during the construction period as well as the capital costs, operating costs and a return on equity once the facility is placed into commercial operation. In March 2008,April 2009, the WVPSC granted intervention to several parties and heard oral arguments from APCo, WPCo and intervenors on the CCN to build the plant and the request for cost recovery. Also, in March 2008, various intervenors filed petitions withrequested interim ENEC filing. If the WVPSC were to reconsider the order. No action has been taken on the requests for rehearing. At the timedisallow a material portion of the filing, the cost of the plant was estimated at $2.2 billion. As of September 30, 2008, the estimated cost of the plant has continued to significantly increase. In July 2008, based on the unfavorable order received in Virginia, the WVPSC issued a notice seeking comments from parties on how the WVPSC should proceed. See the “APCo’s Virginia SCC Filing for an IGCC Plant” section above. Through September 30, 2008, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to the West Virginia jurisdictionAPCo’s and approximately $2 million applicable to the FERC jurisdiction. In July 2008, the IRS allocated $134 million in future tax credits to APCo for the planned IGCC plant. Although management continues to pursue the ultimate construction of the IGCC plant, APCo will not start construction of the IGCC plant until sufficient assurance of cost recovery exists. If the 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,WPCo’s requested increase, it would have an adverse effect on future net income and cash flows.
APCo’s Filings for an IGCC Plant
See “APCo’s Filings for an IGCC Plant” section within “Virginia Rate Matters” for disclosure.
Mountaineer Carbon Capture Project
See “Mountaineer Carbon Capture Project” section within “Virginia Rate Matters” for disclosure.
Indiana Rate Matters
Indiana Base Rate Filing
In a January 2008 filing with the IURC, updated in the second quarter of 2008, I&M requested an increase in its Indiana base rates of $80 million including a return on equity of 11.5%. The base rate increase includes theincluded a $69 million annual reduction in depreciation expense previously approved by the IURC and implemented for accounting purposes effective June 2007. The depreciation reduction will no longer favorably impact earnings and will adversely affect cash flows when tariff rates are revised to reflect the effect of the depreciation expense reduction. The filing also requests trackers for certain variable components of the cost of service including recently increased PJM costs associated with transmission line losses due to the implementation of marginal loss pricing and other RTO costs, reliability enhancement costs, demand side management/energy efficiency costs, off-system sales margins and environmental compliance costs. The trackers would initially increase annual revenues by an additional $45 million.In addition, I&M proposesproposed to share with ratepayers,customers, through a proposed tracker, 50% of off-system sales margins initially estimated to be $96 million annually with a guaranteed credit to customers of $20 million.
In SeptemberDecember 2008, I&M and all of the Indiana Officeintervenors jointly filed a settlement agreement with the IURC proposing to resolve all of Utility Consumer Counselor (OUCC) and the Industrial Customer Coalition filed testimony recommendingissues in the case. The settlement agreement incorporated the $69 million annual reduction in revenues from depreciation rate reduction in the development of the agreed to revenue increase of $44 million including a $14$22 million and $37 million decreaseincrease in revenue respectively. Twofrom base rates with an authorized return on equity of 10.5% and a $22 million initial increase in tracker revenue for PJM, net emission allowance and DSM costs. The agreement also establishes an off-system sales sharing mechanism and other intervenors filed testimony on limited issues. The OUCC andprovisions which include continued funding for the Industrial Customer Coalition recommended thateventual decommissioning of the Cook Nuclear Plant. In March 2009, the IURC reduceapproved the ROE proposed by I&M, reduce or limitsettlement agreement, with modifications, that provides for an annual increase in revenues of $42 million including a $19 million increase in revenue from base rates, net of the depreciation rate reduction, and a $23 million increase in tracker revenue. The IURC order removed base rate recovery of the DSM costs but established a tracker with an initial zero amount for DSM costs, adjusted the sharing of off-system sales margin sharing, denymargins to 50% above the $37.5 million included in base rates and approved the recovery of reliability enhancement$7.3 million of previously expensed NSR and OPEB costs which favorably affected first quarter of 2009 net income. In addition, the IURC order requires I&M to review and rejectfile a final report by December 2009 on the proposed environmental compliance cost recovery trackers. effectiveness of the Interconnection Agreement including I&M’s relationship with PJM.
Rockport and Tanners Creek Plants
In October 2008,January 2009, I&M filed testimony rebuttinga petition with the recommendationsIURC requesting approval of a Certificate of Public Convenience and Necessity (CPCN) to use advanced coal technology which would allow I&M to reduce airborne emissions of NOx and mercury from its existing coal-fired steam electric generating units at the Rockport and Tanners Creek Plants. In addition, the petition is requesting approval to construct and recover the costs of selective non-catalytic reduction (SNCR) systems at the Tanners Creek Plant and to recover the costs of activated carbon injection (ACI) systems on both generating units at the Rockport Plant. I&M is requesting to depreciate the ACI systems over an accelerated 10-year period and the SNCR systems over the remaining useful life of the OUCC. HearingsTanners Creek generating units. I&M requested the IURC to approve a rate adjustment mechanism of unrecovered carrying costs during construction and a return on investment, depreciation expense and operation and maintenance costs, including consumables and new emission allowance costs, once the projects are scheduled for December 2008. A decisionplaced in service. I&M also requested the IURC to authorize the deferral of the cost of service of these projects and carrying costs until such costs are recognized in the requested rate adjustment mechanism. Through March 2009, I&M incurred $9 million and $6 million in capitalized project costs related to the Rockport and Tanners Creek Plants, respectively, which are included in Construction Work in Progress. In March 2009, the IURC issued a prehearing conference order setting a procedural schedule. Since the Indiana base rate order included recovery of emission allowance costs, that portion of this request will be eliminated. An order is expected by the third quarter of 2009. Management is unable to predict the outcome of this petition.
Indiana Fuel Clause Filing
In January 2009, I&M filed with the IURC an application to increase its fuel adjustment charge by approximately $53 million for April through September 2009. The filing included an under-recovery for the period ended November 2008, mainly as a result of the extended outage of the Cook Plant Unit 1 (Unit 1) due to fire damage to the main turbine and generator, increased coal prices and a projection for the future period of fuel costs including Unit 1 fire related outage replacement power costs. The filing also included an adjustment, beginning coincident with the receipt of insurance proceeds, to reduce the incremental fuel cost of replacement power with a portion of the insurance proceeds from the Unit 1 accidental outage policy. See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4. I&M reached an agreement in February 2009 with intervenors, which was approved by the IURC by Junein March 2009, to collect the under-recovery over twelve months instead of over six months as proposed. Under the order, the fuel factor will go into effect, subject to refund, and a subdocket will be established to consider issues relating to the Unit 1 fire outage, the use of the insurance proceeds and I&M’s fuel procurement practices. The order provides for the fire outage issues to be resolved subsequent to the date Unit 1 returns to service, which if temporary repairs are successful, could occur as early as October 2009. Management cannot predict the outcome of the pending proceedings, including the treatment of the insurance proceeds, and whether any fuel clause revenues will have to be refunded as a result.
Michigan Rate Matters
In March 2009, I&M filed with the Michigan Restructuring
Although customer choice commenced for I&M’s Michigan customers on January 1, 2002, I&M’s rates for generation in Michigan continuedPublic Service Commission its 2008 power supply cost recovery reconciliation. The filing also included an adjustment to be cost-based regulated because nonereduce the incremental fuel cost of I&M's customers elected to change suppliers and no alternative electric suppliers were registered to compete in I&M's Michigan service territory. In October 2008, the Governor of Michigan signed legislation to limit customer choice load to no more than 10%replacement power with a portion of the annual retail load forinsurance proceeds from the preceding calendar yearCook Plant Unit 1 accidental outage policy. See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4. Management is unable to requirepredict the remaining 90%outcome of annual retail load to be phased into cost-based rates. The new legislation also requires utilities to meet certain energy efficiency and renewable portfolio standards and requires cost recovery of meeting those standards. Management continues to conclude that I&M's rates for generation in Michigan are cost-based regulated.
Kentucky Rate Matters
Validity of Nonstatutory Surcharges
In August 2007, the Franklin County Circuit Court concluded the KPSC did not have the authority to order a surcharge for a gas company subsidiary of Duke Energy absent a full cost of service rate proceeding due to the lack of statutory authority. The Kentucky Attorney General (AG) notified the KPSC that the Franklin County Circuit Court judge’s order in the Duke Energy case can be interpreted to include other existing surcharges, rates or fees established outside of the context of a general rate casethis proceeding and not specifically authorized by statute, including fuel clauses. Both the KPSC and Duke Energy appealed the Franklin County Circuit Court decision.
Although this order is not directly applicable, KPCo has existing surcharges which are not specifically authorized by statute. These include KPCo’s fuel clause surcharge, the annual Rockport Plant capacity surcharge, the merger surcredit and the off-system sales credit rider. On an annual basis these surcharges recently ranged from revenues of approximately $10 million to a reduction of revenues of $2 million due to the volatility of these surcharges. The KPSC asked interested parties to brief the issue in KPCo’s fuel cost proceeding. The AG responded that the KPCo fuel clause should be invalidated because the KPSC lacked the authority to implement a fuel clause for KPCo without a full rate case review. The KPSC issued an order stating that it has the authority to provide for surcharges and surcredits until the court of appeals rules. The appeals process could take up to two years to complete. The AG agreed to stay its challenge during that time.
We expect any adverse court of appeals decision could be applied prospectively but it is possible that a retrospective refund could also be ordered. KPCo’s exposure is indeterminable at this time although an adverse decision would have an unfavorable effect on future net income and cash flows, assuming the legislature does not enact legislation that authorizes such surcharges.
2008 Fuel Cost Reconciliation
In January 2008, KPCo filed its semi-annual fuel cost reconciliation covering the period May 2007 through October 2007. As part of this filing, KPCo sought recovery of incremental costs associated with transmission line losses billed by PJM since June 2007 due to PJM’s implementation of marginal loss pricing. KPCo expensed these incremental PJM costs associated with transmission line losses pending a determination that they are recoverable through the Kentucky fuel clause. In June 2008, the KPSC issued an order approving KPCo’s semi-annual fuel cost reconciliation filing and recovery of incremental costs associated with transmission line losses billed by PJM. For the nine months ended September 30, 2008, KPCo recorded $16 million of income and the related Regulatory Asset for Under-Recovered Fuel Costs for transmission line losses incurred from June 2007 through September 2008 of which $7 million related to 2007.flows.
Oklahoma Rate Matters
PSO Fuel and Purchased Power
The Oklahoma Industrial Energy Consumers appealed an ALJ recommendation2006 and Prior Fuel and Purchased Power
Proceedings addressing PSO’s historic fuel costs from 2001 through 2006 remain open at the OCC due to the issue of the allocation of off-system sales margins among the AEP operating companies in June 2008 regardingaccordance with a pendingFERC-approved allocation agreement.
In 2002, PSO under-recovered $42 million of fuel case involving thecosts resulting from a reallocation of $42 millionamong AEP West companies of purchased power costs among AEP West companies infor periods prior to 2002. The Oklahoma Industrial Energy Consumers requested that PSO be required to refund this $42 million of reallocated purchased power costs through its fuel clause. PSO had recovered the $42 million by offsetting it against an existing fuel over-recovery during the period June 2007 through May 2008. In June 2008, the Oklahoma Industrial Energy Consumers (OIEC) appealed an ALJ recommendation that concluded it was a FERC jurisdictional matter which allowed PSO to retain the $42 million it recovered from ratepayers. The OIEC requested that PSO be required to refund the $42 million through its fuel clause. In August 2008, the OCC heard the OIEC appeal and a decision is pending.
In February 2006, the OCC enacted a rule, requiring the OCC staff to conduct prudence reviews For further discussion and estimated effect on PSO’s generation and fuel procurement processes, practices and costs on a periodic basis. PSO filed testimony in June 2007 covering a prudence review for the year 2005. The OCC staff and intervenors filed testimony in September 2007, and hearings were held in November 2007. The only major issue in the proceeding was the alleged under allocation of off-system sales credits under the FERC-approved allocation methodology, which previously was determined not to be jurisdictional to the OCC. Seenet income, see “Allocation of Off-system Sales Margins” section within “FERC Rate Matters”. Consistent with the prior OCC determination, the ALJ found that the OCC lacked authority to alter the FERC-approved allocation methodology and that PSO’s fuel costs were prudent. The intervenors appealed the ALJ recommendation and the OCC heard the appeal in August 2008. In August 2008, the OCC filed a complaint at the FERC alleging that AEPSC inappropriately allocated off-system trading margins between the AEP East companies and the AEP West companies and did not properly allocate off-system trading margins within the AEP West companies.
In November 2007 PSO filed testimony in another proceeding to address its fuel costs for 2006. In April 2008, intervenor testimony was filed again challenging the allocation of off-system sales credits during the portion of the year when the allocation was in effect. Hearings were held in July 2008Fuel and the OCC changed the scope of the proceeding from a prudence review to only a review of the mechanics of the fuel cost calculation. No party contested PSO’s fuel cost calculation. In August 2008, the OCC issued a final order that PSO’s calculations of fuel and purchased power costs were accurate and are consistent with PSO’s fuel tariff.Purchased Power
In September 2008, the OCC initiated a review of PSO’s generation, purchased power and fuel procurement processes and costs for 2007. Under the OCC minimum filing requirements, PSO is required to file testimony and supporting data within 60 days which will occur in the fourth quarter of 2008. Management cannot predict the outcome of the pending fuel and purchased power cost recovery filings or prudence reviews.filings. However, PSO believes its fuel and purchased power procurement practices and costs were prudent and properly incurred and therefore are legally recoverable.
Red Rock Generating Facility
In July 2006, PSO announced an agreement with Oklahoma Gas and Electric Company (OG&E) to build a 950 MW pulverized coal ultra-supercritical generating unit. PSO would own 50% of the new unit. Under the agreement, OG&E would manage construction of the plant. OG&E and PSO requested pre-approval to construct the coal-fired Red Rock Generating Facility (Red Rock) and to implement a recovery rider.
In October 2007, the OCC issued a final order approving PSO’s need for 450 MWs of additional capacity by the year 2012, but rejected the ALJ’s recommendation and denied PSO’s and OG&E’s applications for construction pre-approval. The OCC stated that PSO failed to fully study other alternatives to a coal-fired plant. Since PSO and OG&E could not obtain pre-approval to build Red Rock, PSO and OG&E cancelled the third party construction contract and their joint venture development contract. In June 2008, PSO issued a request-for-proposal to meet its capacity and energy needs.
In December 2007, PSO filed an application at the OCC requesting recovery of $21 million in pre-construction costs and contract cancellation fees associated with Red Rock. In March 2008, PSO and all other parties in this docket signed a settlement agreement that provides for recovery of $11 million of Red Rock costs, and provides carrying costs at PSO’s AFUDC rate beginning in March 2008 and continuing until the $11 million is included in PSO’s next base rate case. PSO will recover the costs over the expected life of the peaking facilities at the Southwestern Station, and include the costs in rate base in its next base rate filing. The settlement was filed with the OCC in March 2008. The OCC approved the settlement in May 2008. As a result of the settlement, PSO wrote off $10 million of its deferred pre-construction costs/cancellation fees in the first quarter of 2008. In July 2008, PSO filed a base rate case which included $11 million of deferred Red Rock costs plus carrying charges at PSO’s AFUDC rate beginning in March 2008. See “2008 Oklahoma Base Rate Filing” section below.
Oklahoma 2007 Ice Storms
In October 2007, PSO filed with the OCC requesting recovery of $13 million of operation and maintenance expense related to service restoration efforts after a January 2007 ice storm. PSO proposed in its application to establish a regulatory asset of $13 million to defer the previously expensed January 2007 ice storm restoration costs and to amortize the regulatory asset coincident with gains from the sale of excess SO2 emission allowances. In December 2007, PSO expensed approximately $70 million of additional storm restoration costs related to the December 2007 ice storm.
In February 2008, PSO entered into a settlement agreement for recovery of costs from both ice storms. In March 2008, the OCC approved the settlement subject to an audit of the final December ice storm costs filed in July 2008. As a result, PSO recorded an $81 million regulatory asset for ice storm maintenance expenses and related carrying costs less $9 million of amortization expense to offset recognition of deferred gains from sales of SO2 emission allowances. Under the settlement agreement, PSO would apply proceeds from sales of excess SO2 emission allowances of an estimated $26 million to recover part of the ice storm regulatory asset. The settlement also provided for PSO to amortize and recover the remaining amount of the regulatory asset through a rider over a period of five years beginning in the fourth quarter of 2008. The regulatory asset will earn a return of 10.92% on the unrecovered balance.
In June 2008, PSO adjusted its regulatory asset to true-up the estimated costs to actual costs. After the true-up, application of proceeds from to-date sales of excess SO2 emission allowances and carrying costs, the ice storm regulatory asset was $64 million. The estimate of future gains from the sale of SO2 emission allowances has significantly declined with the decrease in value of such allowances. As a result, estimated collections from customers through the special storm damage recovery rider will be higher than the estimate in the settlement agreement. In July 2008, as required by the settlement agreement, PSO filed its reconciliation of the December 2007 storm restoration costs along with a proposed tariff to recover the amounts not offset by the sales of SO2 emission allowances. In September 2008, the OCC staff filed testimony supporting PSO’s filing with minor changes. In October 2008, an ALJ recommended that PSO recover $62 million of the December 2007 storm restoration costs before consideration of emission allowance gains and carrying costs. In October 2008, the OCC approved the filing which allows PSO to recover $62 million of the December 2007 storm restoration costs beginning in November 2008.
2008 Oklahoma Annual Fuel Factor Filing
In May 2008, pursuant to its tariff, PSO filed its annual update with the OCC for increases in the various service level fuel factors based on estimated increases in fuel costs, primarily natural gas and purchased power expenses, of approximately $300 million. The request included recovery of $26 million in under-recovered deferred fuel. In June 2008, PSO implemented the fuel factor increase. Because of the substantial increase, the OCC held an administrative proceeding to determine whether the proposed charges were based upon the appropriate coal, purchased gas and purchased power prices and were properly computed. In June 2008, the OCC ordered that PSO properly estimated the increase in natural gas prices, properly determined its fuel costs and, thus, should implement the increase.
2008 Oklahoma Base Rate Filing
In July 2008, PSO filed an application with the OCC to increase its base rates by $133 million (later adjusted to $127 million) on an annual basis. PSO recovershas been recovering costs related to new peaking units recently placed into service through thea Generation Cost Recovery Rider (GCRR). UponSubsequent to implementation of the new base rates, the GCRR will terminate and PSO will recover these costs through the new base rates and the GCRR will terminate.rates. Therefore, PSO’s net annual requested increase in total revenues iswas actually $117 million. The requested increase is based upon a test year ended February 29, 2008,million (later adjusted for known and measurable changes through August 2008, which is consistent with the ratemaking treatment adopted by the OCC in PSO’s 2006 base rate case.to $111 million). The proposed revenue requirement reflectsreflected a return on equity of 11.25%. PSO expects hearings to begin
In January 2009, the OCC issued a final order approving an $81 million increase in December 2008PSO’s non-fuel base revenues and newa 10.5% return on equity. The rate increase includes a $59 million increase in base rates and a $22 million increase for costs to become effectivebe recovered through riders outside of base rates. The $22 million increase includes $14 million for purchase power capacity costs and $8 million for the recovery of carrying costs associated with PSO’s program to convert overhead distribution lines to underground service. The $8 million recovery of carrying costs associated with the overhead to underground conversion program will occur only if PSO makes the required capital expenditures. The final order approved lower depreciation rates and also provides for the deferral of $6 million of generation maintenance expenses to be recovered over a six-year period. This deferral was recorded in the first quarter of 2009. In October 2008,Additional deferrals were approved for distribution storm costs above or below the amount included in base rates and for certain transmission reliability expenses. The new rates reflecting the final order were implemented with the first billing cycle of February 2009.
PSO filed an appeal with the Oklahoma Supreme Court challenging an adjustment the OCC staff,made on prepaid pension funding contained within the OCC final order. In February 2009, the Oklahoma Attorney General and several intervenors also filed appeals with the Oklahoma Supreme Court raising several issues. If the Attorney General’s office,General and/or the intervenor’s Supreme Court appeals are successful, it could have an adverse effect on future net income and a group of industrial customers filed testimony recommending annual base rate increases of $86 million, $68 million and $29 million, respectively. The differences are principally due to the use of recommended return on equity of 10.88%, 10% and 9.5% by the OCC staff, the Attorney General’s office, and a group of industrial customers. The OCC staff and the Attorney General’s office recommended $22 million and $8 million, respectively, of costs included in the filing be recovered through the fuel adjustment clause and riders outside of base rates.cash flows.
Louisiana Rate Matters
Louisiana Compliance2008 Formula Rate Filing
In connection with SWEPCo’s merger related compliance filings, the LPSC approved a settlement agreement in April 2008 that prospectively resolves all issues regarding claims that SWEPCo had over-earned its allowed return. SWEPCo agreed to a formula rate plan (FRP) with a three-year term. Under the plan, beginning in August 2008, rates shall be established to allow SWEPCo to earn an adjusted return on common equity of 10.565%. The adjustments are standard Louisiana rate filing adjustments.
If in the second and third year of the FRP, the adjusted earned return is within the range of 10.015% to 11.115%, no adjustment to rates is necessary. However, if the adjusted earned return is outside of the above-specified range, an FRP rider will be established to increase or decrease rates prospectively. If the adjusted earned return is less than 10.015%, SWEPCo will prospectively increase rates to collect 60% of the difference between 10.565% and the adjusted earned return. Alternatively, if the adjusted earned return is more than 11.115%, SWEPCo will prospectively decrease rates by 60% of the difference between the adjusted earned return and 10.565%. SWEPCo will not record over/under recovery deferrals for refund or future recovery under this FRP.
The settlement provides for a separate credit rider decreasing Louisiana retail base rates by $5 million prospectively over the entire three-year term of the FRP, which shall not affect the adjusted earned return in the FRP calculation. This separate credit rider will cease effective August 2011.
In addition, the settlement provides for a reduction in generation depreciation rates effective October 2007. SWEPCo will defer as a regulatory liability, the effects of the expected depreciation reduction through July 2008. SWEPCo will amortize this regulatory liability over the three-year term of the FRP as a reduction to the cost of service used to determine the adjusted earned return. In August 2008, the LPSC issued an order approving the settlement.
In April 2008, SWEPCo filed the first FRPformula rate plan (FRP) which would increase its annual Louisiana retail rates by $11 million in August 2008 to earn an adjusted return on common equity of 10.565%. In accordance with the settlement, SWEPCo recorded a $4 million regulatory liability related to the reduction in generation depreciation rates. The amount of the unamortized regulatory liability for the reduction in generation depreciation was $4 million as of September 30, 2008. In August 2008, SWEPCo implemented the FRP rates, subject to refund. No provision for refund has been recorded as SWEPCo believes that the rates as implemented are in compliance with the FRP methodology approved by the LPSC. The LPSC staff reviews SWEPCo’shas not approved the rates being collected. If the rates are not approved as filed, it could have an adverse effect on future net income and cash flows.
2009 Formula Rate Filing
In April 2009, SWEPCo filed the second FRP filing andwhich would increase its annual Louisiana retail rates by an additional $4 million in August 2009 pursuant to the production depreciation study.formula rate methodology. SWEPCo believes that the rates as filed are in compliance with the FRP methodology previously approved by the LPSC.
Stall Unit
In May 2006, SWEPCo announced plans to build a new intermediate load, 500 MW, natural gas-fired, combustion turbine, combined cycle generating unit (the Stall Unit) at its existing Arsenal Hill Plant location in Shreveport, Louisiana. SWEPCo submitted the appropriate filings to the PUCT, the APSC, the LPSC and the Louisiana Department of Environmental Quality to seek approvals to construct the unit. The Stall Unit is currently estimated to cost $378$385 million, excluding AFUDC, and is expected to be in-service in mid-2010. The Louisiana Department of Environmental Quality issued an air permit for the Stall unit in March 2008.
In March 2007, the PUCT approved SWEPCo’s request for a certificate of necessity for the facility based on a prior cost estimate. In SeptemberJuly 2008, a Louisiana ALJ issued a recommendation that SWEPCo be authorized to construct, own and operate the Stall Unit and recommended that costs be capped at $445 million (excluding transmission). In October 2008, the LPSC approved SWEPCo’s request for certificationissued a final order effectively approving the ALJ recommendation. In December 2008, SWEPCo submitted an amended filing seeking approval from the APSC to construct the Stall Plant.unit. The APSC has not established a procedural schedule at this time. The Louisiana Department of Environmental Quality issued an air permit for the unitstaff filed testimony in March 2008. 2009 supporting the approval of the plant. The APSC staff also recommended that costs be capped at $445 million (excluding transmission). A hearing that had been scheduled for April 2009 was cancelled and the APSC will issue its decision based on the amended application and prefiled testimony.
If SWEPCo does not receive appropriate authorizations and permits to build the Stall Unit, SWEPCo would seek recovery of the capitalized pre-constructionconstruction costs including any cancellation fees. As of September 30, 2008,March 31, 2009, SWEPCo has capitalized pre-constructionconstruction costs of $158$291 million (including AFUDC) and has contractual construction commitments of an additional $145$74 million. As of September 30, 2008,March 31, 2009, if the plant had been cancelled, cancellation fees of $61$40 million would have been required in order to terminate thesethe construction commitments. If SWEPCo cancels the plant and 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.
Turk Plant
See “Turk Plant” section within Arkansas“Arkansas Rate MattersMatters” for disclosure.
Arkansas Rate Matters
Turk Plant
In August 2006, SWEPCo announced plans to build the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas. Ultra-supercritical technology uses higher temperatures and higher pressures to produce electricity more efficiently thereby using less fuel and providing substantial emissions reductions. SWEPCo submitted filings with the APSC, the PUCT and the LPSC seeking certification of the plant. SWEPCo will own 73% of the Turk Plant and will operate the facility. During 2007, SWEPCo signed joint ownership agreements with the Oklahoma Municipal Power Authority (OMPA), the Arkansas Electric Cooperative Corporation (AECC) and the East Texas Electric Cooperative (ETEC) for the remaining 27% of the Turk Plant. During 2007, OMPA exercised its participation option. During the first quarter of 2009, AECC and ETEC exercised their participation options and paid SWEPCo $104 million. SWEPCo recorded a $2.2 million gain from the transactions. The Turk Plant is currently estimated to cost $1.5$1.6 billion, excluding AFUDC, with SWEPCo’s portion estimated to cost $1.1$1.2 billion. If approved on a timely basis, the plant is expected to be in-service in 2012.
In November 2007, the APSC granted approval to build the plant.Turk Plant. Certain landowners filed a notice of appealhave appealed the APSC’s decision 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 $1.5previously estimated $1.522 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 emissionsemission costs exceed the restrictions, it could have a material adverse impacteffect 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.
A request to stop pre-construction activities at the site was filed in federal court by Arkansas landowners. 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 2009, SWEPCo is also working withfiled a motion to dismiss the appeal. In March 2009, the motion was granted.
In November 2008, SWEPCo received the required air permit approval from the Arkansas Department of Environmental Quality forand commenced construction. In December 2008, Arkansas landowners filed an appeal with the approvalArkansas Pollution Control and Ecology Commission (APCEC) which caused construction of the Turk Plant to halt until the APCEC took further action. In December 2008, SWEPCo filed a request with the APCEC to continue construction of the Turk Plant and the APCEC ruled to allow construction to continue while an appeal of the Turk Plant’s permit is heard. Hearings on the air permit andappeal is scheduled for June 2009. SWEPCo is also working with the U.S. Army Corps of Engineers for the approval of a wetlands and stream impact permit. OnceIn March 2009, 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 denialreported to the U.S. CourtArmy Corps of Appeals.Engineers a potential wetlands impact on approximately 2.5 acres at the Turk Plant. The U.S. Army Corps of Engineers directed SWEPCo to cease further work impacting the wetland areas. Construction has continued on other areas of the Turk Plant. The impact on the construction schedule and workforce is currently being evaluated by management.
In January 2008 and July 2008, SWEPCo filed Certificate of Environmental Compatibility and Public Need (CECPN) 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. TheIn June 2008, the landowner filed an appeal to the Arkansas State Court of Appeals in June 2008.requesting to re-litigate Turk Plant issues. SWEPCo responded and the appeal was dismissed. In January 2009, the APSC approved the CECPN applications.
The Arkansas Governor’s Commission on Global Warming is scheduled to issueissued its final report to the Governor by November 1,governor in October 2008. The Commission was established to set a global warming pollution reduction goal together with a strategic plan for implementation in Arkansas. The Commission’s final report included a recommendation that the Turk Plant employ post combustion carbon capture and storage measures as soon as it starts operating. If legislation is passed as a result of the findings in the Commission’s report, it could impact SWEPCo’s proposal to build and operate 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 paidcosts incurred plus related shutdown 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,March 31, 2009, SWEPCo has capitalized approximately $448$480 million of expenditures (including AFUDC) and has significant contractual construction commitments for an additional $771$655 million. As of September 30, 2008,March 31, 2009, if the plant had been cancelled, SWEPCo would have incurred cancellation fees of $61$100 million. 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.
Arkansas Base Rate Filing
In February 2009, SWEPCo filed an application with the APSC for a base rate increase of $25 million based on a requested return on equity of 11.5%. SWEPCo also requested a separate rider to recover financing costs related to the construction of the Stall and Turk generating facilities. These financing costs are currently being capitalized as AFUDC in Arkansas. A decision is not expected until the fourth quarter of 2009 or the first quarter of 2010.
Stall Unit
See “Stall Unit” section within Louisiana“Louisiana Rate MattersMatters” for disclosure.
FERC Rate Matters
Regional Transmission Rate Proceedings at the FERC
SECA Revenue Subject to Refund
Effective December 1, 2004, AEP eliminated transaction-based through-and-out transmission service (T&O) charges in accordance with FERC orders and collected, at the FERC’s direction, load-based charges, referred to as RTO SECA, to partially mitigate the loss of T&O revenues on a temporary basis through March 31, 2006. Intervenors objected to the temporary SECA rates, raising various issues. As a result, the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund. The AEP East companies paid SECA rates to other utilities at considerably lesser amounts than they collected. If a refund is ordered, the AEP East companies would also receive refunds related to the SECA rates they paid to third parties. The AEP East companies recognized gross SECA revenues of $220 million from December 2004 through March 2006 when the SECA rates terminated leaving the AEP East companies and ultimately their internal load retail customers to make up the short fall in revenues.
In August 2006, a FERC ALJ issued an initial decision, finding that the rate design for the recovery of SECA charges was flawed and that a large portion of the “lost revenues” reflected in the SECA rates should not have been recoverable. The ALJ found that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made. The ALJ also found that the unpaid SECA rates must be paid in the recommended reduced amount.
In September 2006, AEP filed briefs jointly with other affected companies noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part. Management believes, based on advice of legal counsel, that the FERC should reject the ALJ’s initial decision because it contradicts prior related FERC decisions, which are presently subject to rehearing. Furthermore, management believes the ALJ’s findings on key issues are largely without merit. AEP and SECA ratepayers haveare engaged in settlement discussions in an effort to settle the SECA issue. However, if the ALJ’s initial decision is upheld in its entirety, it could result in a disallowance of a large portion onof any unsettled SECA revenues.
During 2006, basedBased on anticipated settlements, the AEP East companies provided reserves for net refunds for current and future SECA settlements totaling $37$39 million and $5 million in 2006 and 2007, respectively, applicable to a total of $220 million of SECA revenues. In February 2009, a settlement agreement was approved by the FERC resulting in the completion of a $1 million settlement applicable to $20 million of SECA revenue. Including this most recent settlement, AEP has completed settlements totaling $7$10 million applicable to $75$112 million of SECA revenues. The balance in the reserve for future settlements as of September 2008March 2009 was $35$34 million. In-process settlements total $3 million applicable to $37 millionAs of SECA revenues. Management believes that the available $32 million of reserves for possible refunds are sufficient to settle the remaining $108 million of contested SECA revenues.March 31, 2009, there were no in-process settlements.
If the FERC adopts the ALJ’s decision and/or AEP cannot settle all of the remaining unsettled claims within the remaining amount reserved for refund, it will have an adverse effect on future net income and cash flows. Based on advice of external FERC counsel, recent settlement experience and the expectation that most of the unsettled SECA revenues will be settled, management believes that the remainingavailable reserve of $32$34 million is adequate to cover allsettle the remaining settlements.$108 million of contested SECA revenues. If the remaining unsettled SECA claims are settled for considerably more than the to-date settlements or if the remaining unsettled claims are awarded a refund by the FERC greater than the remaining reserve balance, it could have an adverse effect on net income. Cash flows will be adversely impacted by any additional settlements or ordered refunds. However, management cannot predict the ultimate outcome of ongoing settlement discussions or future FERC proceedings or court appeals, if necessary.any.
The FERC PJM Regional Transmission Rate Proceeding
With the elimination of T&O rates, the expiration of SECA rates and after considerable administrative litigation at the FERC in which AEP sought to mitigate the effect of the T&O rate elimination, the FERC failed to implement a regional rate in PJM. As a result, the AEP East companies’ retail customers incur the bulk of the cost of the existing AEP east transmission zone facilities. However, the FERC ruled that the cost of any new 500 kV and higher voltage transmission facilities built in PJM would be shared by all customers in the region. It is expected that most of the new 500 kV and higher voltage transmission facilities will be built in other zones of PJM, not AEP’s zone. The AEP East companies will need to obtain state regulatory approvals for recovery of any costs of new facilities that are assigned to them. AEP requested rehearing of this order, which the FERC denied.them by PJM. In February 2008, AEP filed a Petition for Review of the FERC orders in this case in the United States Court of Appeals. Management cannot estimate at this time what effect, if any, this order will have on the AEP East companies’ future construction of new transmission facilities, net income and cash flows.
The AEP East companies filed for and in 2006 obtained increases in their wholesale transmission rates to recover lost revenues previously applied to reduce those rates. AEP has also sought and received retail rate increases in Ohio, Virginia, West Virginia and Kentucky. In January and March 2009, AEP received retail rate increases in Tennessee and Indiana, respectively, that recognized the higher retail transmission costs resulting from the loss of wholesale transmission revenues from T&O transactions. As a result, AEP is now recovering approximately 80%98% of the lost T&O transmission revenues. AEP received net SECA transmission revenues of $128 millionThe remaining 2% is being incurred by I&M until it can revise its rates in 2005. I&M requested recovery of these lost revenues in its Indiana rate filing in January 2008 but does not expectMichigan to commence recovering the new rates until early 2009. Future net income and cash flows will continue to be adversely affected in Indiana and Michigan until the remaining 20% ofrecover the lost T&O transmission revenues are recovered in retail rates.revenues.
The FERC PJM and MISO Regional Transmission Rate Proceeding
In the SECA proceedings, the FERC ordered the RTOs and transmission owners in the PJM/MISO region (the Super Region) to file, by August 1, 2007, a proposal to establish a permanent transmission rate design for the Super Region to be effective February 1, 2008. All of the transmission owners in PJM and MISO, with the exception of AEP and one MISO transmission owner, elected to support continuation of zonal rates in both RTOs. In September 2007, AEP filed a formal complaint proposing a highway/byway rate design be implemented for the Super Region where users pay based on their use of the transmission system. AEP argued the use of other PJM and MISO facilities by AEP is not as large as the use of AEP transmission by others in PJM and MISO. Therefore, a regional rate design change is required to recognize that the provision and use of transmission service in the Super Region is not sufficiently uniform between transmission owners and users to justify zonal rates. In January 2008, the FERC denied AEP’s complaint. AEP filed a rehearing request with the FERC in March 2008. Should this effort beIn December 2008, the FERC denied AEP’s request for rehearing. In February 2009, AEP filed an appeal in the U.S. Court of Appeals. If the court appeal is successful, earnings could benefit for a certain period of time due to regulatory lag until the AEP East companies reduce future retail revenues in their next fuel or base rate proceedings.proceedings to reflect the resultant additional transmission cost reductions. Management is unable to predict the outcome of this case.
PJM Transmission Formula Rate Filing
In July 2008, AEP filed an application with the FERC to increase its rates for wholesale transmission service within PJM by $63 million annually. The filing seeks to implement a formula rate allowing annual adjustments reflecting future changes in AEP'sthe AEP East companies' cost of service. In September 2008, the FERC issued an order conditionally accepting AEP’s proposed formula rate, subject to a compliance filing, established a settlement proceeding with an ALJ, and delayed the requested October 2008 effective date for five months. The requested increase, would resultwhich the AEP East companies began billing in additional annual revenuesApril 2009 for service as of approximately $9March 1, 2009, will produce a $63 million annualized increase in revenues. Approximately $8 million of the increase will be collected from nonaffiliated customers within PJM. The remaining $54$55 million requested would be billed to the AEP East companies tobut would be recovered inoffset by compensation from PJM for use of the AEP East companies’ transmission facilities so that retail rates. Retail rates for jurisdictions other than Ohio are not affected until the next base rate filing at FERC.directly affected. Retail rates for CSPCo and OPCo would be adjustedincreased through the Transmission Cost Recovery Rider (TCRR)TCRR totaling approximately $10 million and $12$13 million, respectively. The TCRR includes a true-up mechanism so CSPCo’s and OPCo’s net income will not be adversely affected by a FERC ordered transmission rate increase. Other jurisdictions would be recoverable on a lag basis as base rates are changed.In October 2008, AEP requested an effective date of October 1, 2008. In September 2008,filed the FERC issued an order conditionally accepting AEP’s proposed formula rate, subject to arequired compliance filing, suspendedand began settlement discussions with the intervenors and FERC staff. The settlement discussions are currently ongoing. Under the formula, rates will be updated effective date until MarchJuly 1, 2009, and established a settlement proceedingeach year thereafter. Also, beginning with the July 1, 2010 update, the rates each year will include an ALJ.adjustment to true-up the prior year's collections to the actual costs for the prior year. Management is unable to predict the outcome of this filing.the settlement discussions or any further proceedings that might be necessary if settlement discussions are not successful.
FERC Market Power Mitigation
The FERC allows utilities to sell wholesale power at market-based rates if they can demonstrate that they lack market power in the markets in which they participate. Sellers with market rate authority must, at least every three years, update their studies demonstrating lack of market power. In December 2007, AEP filed its most recent triennial update. In March and May 2008, the PUCO filed comments suggesting that the FERC should further investigate whether AEP continues to pass the FERC’s indicative screens for the lack of market power in PJM. Certain industrial retail customers also requested the FERC to further investigate this matter. AEP responded that its market power studies were performed in accordance with the FERC’s guidelines and continue to demonstrate lack of market power. In September 2008, the FERC issued an order accepting AEP’s market-based rates with minor changes and rejected the PUCO’s and the industrial retail customers’ suggestions to further investigate AEP’s lack of market power.
In an unrelated matter, in May 2008, the FERC issued an order in response to a complaint from the state of Maryland’s Public Service Commission to hold a future hearing to review the structure of the three pivotal market power supplier tests in PJM. In September 2008, PJM filed a report on the results of the PJM stakeholder process concerning the three pivotal supplier market power tests which recommended the FERC not make major revisions to the test because the test is not unjust or unreasonable.
The FERC’s order will become final if no requests for rehearing are filed. If a request for rehearing is filed and ultimately results in a further investigation by the FERC which limits AEP’s ability to sell power at market-based rates in PJM, it would result in an adverse effect on future off-system sales margins and cash flows.
Allocation of Off-system Sales Margins
In 2004, intervenors and the OCC staff argued that AEP had inappropriately under-allocated off-system sales credits to PSO by $37 million for the period June 2000 to December 2004 under a FERC-approved allocation agreement. An ALJ assigned to hear intervenor claims found that the OCC lacked authority to examine whether AEP deviated from the FERC-approved allocation methodology for off-system sales margins and held that any such complaints should be addressed at the FERC. In October 2007, the OCC adopted the ALJ’s recommendation and orally directed the OCC staff to explore filing a complaint at the FERC alleging the allocation of off-system sales margins to PSO is not in compliance with the FERC-approved methodology which could result in an adverse effect on future net income and cash flows for AEP Consolidated, the AEP East companies and the AEP West companies. In June 2008, the ALJ issued a final recommendation and incorporated the prior finding that the OCC lacked authority to review AEP’s application of a FERC-approved methodology. In June 2008, the Oklahoma Industrial Energy Consumers appealed the ALJ recommendation to the OCC. In August 2008, the OCC heard the appeal and a decision is pending. See “PSO Fuel and Purchased Power” section within “Oklahoma Rate Matters”. In August 2008, the OCC filed a complaint at the FERC alleging that AEPSCAEP inappropriately allocated off-system tradingsales margins between the AEP East companies and the AEP West companies and did not properly allocate off-system tradingsales margins within the AEP West companies. The PUCT, the APSC and the Oklahoma Industrial Energy Consumers have all intervened in this filing.
TCC, TNC In November 2008, the FERC issued a final order concluding that AEP inappropriately deviated from off-system sales margin allocation methods in the SIA and the PUCT have been involved in litigation inCSW Operating Agreement for the federal courts concerning whetherperiod June 2000 through March 2006. The FERC ordered AEP to recalculate and reallocate the PUCT has the right to order a reallocation of off-system sales margins thereby reducing recoverable fuel costsin compliance with the SIA and to have the AEP East companies issue refunds to the AEP West companies. Although the FERC determined that AEP deviated from the CSW Operating Agreement, the FERC determined the allocation methodology was reasonable. The FERC ordered AEP to submit a revised CSW Operating Agreement for the period June 2000 to March 2006. In December 2008, AEP filed a motion for rehearing and a revised CSW Operating Agreement for the period June 2000 to March 2006. The motion for rehearing is still pending. In January 2009, AEP filed a compliance filing with the FERC and refunded approximately $250 million from the AEP East companies to the AEP West companies. The AEP West companies shared a portion of such revenues with their wholesale and retail customers during the period June 2000 to March 2006. In December 2008, the AEP West companies recorded a provision for refund. In January 2009, SWEPCo refunded approximately $13 million to FERC wholesale customers. In February 2009, SWEPCo filed a settlement agreement with the PUCT that provides for the Texas retail jurisdiction amount to be included in the finalMarch 2009 fuel reconciliation in Texas undercost report submitted to the restructuring legislation. In 2005,PUCT. PSO began refunding approximately $54 million plus accrued interest to Oklahoma retail customers through the fuel adjustment clause over a 12-month period beginning with the March 2009 billing cycle. TCC and TNC recorded provisions for refunds after the PUCT ordered such reallocation. After receipt of favorable federal court decisions and the refusalin Texas filed applications in April 2009 to initiate proceedings as a result of the U.S. Supreme Court to hear a PUCT appeal of the TNC decision,FERC ruling. TCC and TNC reversed their provisions of $16 million and $9 million, respectively,propose to use the refund to reduce its AMS investment as discussed in the third quarter of 2007.
“Advanced Metering System” section within “Texas Rate Matters”. SWEPCo is working with the APSC and the LPSC to determine the effect the FERC order will have on retail rates. Management cannot predict the outcome of these proceedings. However, managementthe requested FERC rehearing proceeding or any future state regulatory proceedings but believes its allocations were in accordance with the then-existing FERC-approved allocation agreements and additional off-system sales margins should not be retroactively reallocated. The results of these proceedings could have an adverse effect on future net income and cash flows for AEP Consolidated, the AEP East companies and the AEP West companies.companies’ provision for refund regarding future regulatory proceedings is adequate.
4. | COMMITMENTS, GUARANTEES AND CONTINGENCIES |
We are subject to certain claims and legal actions arising in our ordinary course of business. In addition, our business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against us cannot be predicted. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on our financial statements. The Commitments, Guarantees and Contingencies note within our 20072008 Annual Report should be read in conjunction with this report.
GUARANTEES
There areWe record certain immaterial liabilities recorded for guarantees in accordance with FASB Interpretation No.FIN 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” In addition, we adopted FSP SFAS 133-1 and FIN 45-4 “Disclosures about Credit Derivatives and Certain Guarantees: An amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161” effective December 31, 2008. There is no collateral held in relation to any guarantees in excess of our ownership percentages. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.
Letters Of Credit
We enter into standby letters of credit (LOCs) with third parties. These LOCs cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. As the Parent, we issued all of these LOCs in our ordinary course of business on behalf of our subsidiaries. At September 30, 2008,March 31, 2009, the maximum future payments for all the LOCs issued under the two $1.5 billion credit facilities, are $67 million with maturities ranging from October 2008 to October 2009. The two $1.5 billion credit facilitieswhich were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $46 million following its bankruptcy.bankruptcy, are approximately $120 million with maturities ranging from May 2009 to March 2010.
In April 2008, we entered intoWe have 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. As of September 30, 2008,March 31, 2009, $372 million of letters of credit were issued by subsidiaries under the $650 million 3-year credit agreement to support variable rate demand notes.Pollution Control Bonds. In April 2009, the $350 million 364-day credit agreement expired.
Guarantees Of Third-Party Obligations
SWEPCo
As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation in the amount of approximately $65 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), an entity consolidated under FIN 46R. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study, we estimate the reserves will be depleted in 2029 with final reclamation completed by 2036, at an estimated cost of approximately $39 million. As of September 30, 2008,March 31, 2009, SWEPCo has collected approximately $37$39 million through a rider for final mine closure costs, of which approximately $7$3 million is recorded in Other Current Liabilities, $5 million is recorded in Asset Retirement Obligations and $25$20 million is recorded in Deferred Credits and Other and approximately $16 million is recorded in Asset Retirement Obligations on our Condensed Consolidated Balance Sheets.
Sabine charges SWEPCo, its only customer, all its costs. SWEPCo passes these costs to customers through its fuel clause.
Indemnifications And Other Guarantees
Contracts
We enter into several types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, our exposure generally does not exceed the sale price. The status of certain sales agreements is discussed in the 20072008 Annual Report, “Dispositions” section of Note 8.7. These sale agreements include indemnifications with a maximum exposure related to the collective purchase price, which is approximately $1.3$1.2 billion. Approximately $1 billion (approximately $1 billionof the maximum exposure relates to the Bank of America (BOA) litigation see(see “Enron Bankruptcy” section of this note)., of which the probable payment/performance risk is $435 million and is recorded in Deferred Credits and Other on our Condensed Consolidated Balance Sheets as of March 31, 2009. The remaining exposure is remote. There are no material liabilities recorded for any indemnifications other than amounts recorded related to the BOA litigation.
Master Operating Lease Agreements
We lease certain equipment under a master operating lease. Underlease agreements. GE Capital Commercial Inc. (GE) notified us in November 2008 that they elected to terminate our Master Leasing Agreements in accordance with the termination rights specified within the contract. In 2010 and 2011, we will be required to purchase all equipment under the lease agreement,and pay GE an amount equal to the unamortized value of all equipment then leased. In December 2008, we signed new master lease agreements with one-year commitment periods that include lease terms of up to 10 years. We expect to enter into additional replacement leasing arrangements for the equipment affected by this notification prior to the termination dates of 2010 and 2011.
For equipment under the GE master lease agreements that expire prior to 2011, the lessor is guaranteed receipt of up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, we are committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. Under the new master lease agreements, the lessor is guaranteed receipt of up to 68% of the unamortized balance at the end of the lease term. If the actual fair market value of the leased equipment is below the unamortized balance at the end of the lease term, we are committed to pay the difference between the actual fair market value and unamortized balance, with the total guarantee not to exceed 68% of the unamortized balance. At March 31, 2009, the maximum potential loss for these lease agreements was approximately $8 million assuming the fair market value of the equipment is zero at the end of the lease term. Historically, at the end of the lease term the fair market value has been in excess of the unamortized balance. At September 30, 2008, the maximum potential loss for these lease agreements was approximately $66 million ($43 million, net of tax) assuming the fair market value of the equipment is zero at the end of the lease term.
Railcar Lease
In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. WeIn January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignment is accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to maintainrenew these leases for the full lease forterm of twenty years, via the renewal options. The future minimum lease obligations are $20 million for I&M and $23 million for SWEPCo for the remaining railcars as of March 31, 2009.
Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines over the current lease term from approximately 84% under the current five-year lease term to 77% at the end of the 20-year term of the projected fair market value of the equipment.
In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignment is accounted for as new operating leases for I&M and SWEPCo. The future minimum lease obligation is $20 million for I&M and $23 million for SWEPCo as of September 30, 2008. I&M and SWEPCo intend to renew these leases for the full remaining terms and have assumed the guarantee under the return-and-sale option. I&M’s maximum potential loss related to the guarantee discussed above is approximately $12 million ($8 million, net of tax) and SWEPCo’s is approximately $14$13 million ($9 million, net of tax) assuming the fair market value of the equipment is zero at the end of the current five-year lease term. However, we believe that the fair market value would produce a sufficient sales price to avoid any loss.
We have other railcar lease arrangements that do not utilize this type of financing structure.
CONTINGENCIES
Federal EPA Complaint and Notice of Violation
The Federal EPA, certain special interest groups and a number of states alleged that APCo, CSPCo, I&MDayton Power and OPCoLight Company and Duke Energy Ohio, Inc. modified certain units at their jointly-owned coal-fired generating plantsunits in violation of the NSR requirements of the CAA. The alleged modifications occurred over a 20-year period. Cases with similar allegations against CSPCo, Dayton Power and Light Company (DP&L) and Duke Energy Ohio, Inc. were also filed related to their jointly-owned units.
The AEP System settled their cases in 2007. In October 2008, the court approved a consent decree for a settlement reached with the Sierra Club in aA case involvingremains pending that could affect CSPCo’s share of jointly-owned units at the StuartBeckjord Station. The Stuart units, operated by DP&L, are equipped with SCR and flue gas desulfurization equipment (FGD or scrubbers) controls. Under the terms of the settlement, the joint-owners agreed to certain emission targets related to NOx, SO2 and PM. They also agreed to make energy efficiency and renewable energy commitments that are conditioned on receiving 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. AnotherBeckjord case involving a jointly-owned Beckjord unit had a liability trial in May 2008. Following the trial, the jury found no liability for claims made against the jointly-owned Beckjord unit. In December 2008, however, the court ordered a new trial in the Beckjord case. Beckjord is operated by Duke Energy Ohio, Inc.
We are unable to estimate the loss or range of loss related to any contingent liability, if any, we might have for civil penalties under the pending CAA proceedings for Beckjord. We are also unable to predict the timing of resolution of these matters. If we do not prevail, we believe we can recover any capital and operating costs of additional pollution control equipment that may be required through future regulated rates or market prices of electricity. If we are unable to recover such costs or if material penalties are imposed, it would adversely affect our net income, cash flows and possibly financial condition.
SWEPCo Notice of Enforcement and Notice of Citizen Suit
In March 2005, two special interest groups, Sierra Club and Public Citizen, filed a complaint in federal district courtFederal District Court for the Eastern District of Texas alleging violations of the CAA at SWEPCo’s Welsh Plant. In April 2008, the parties filed a proposed consent decree to resolve all claims in this case and in the pending appeal of the altered permit for the Welsh Plant. The consent decree requires SWEPCo to install continuous particulate emission monitors at the Welsh Plant, secure 65 MW of renewable energy capacity by 2010, fund $2 million in emission reduction, energy efficiency or environmental mitigation projects by 2012 and pay a portion of plaintiffs’ attorneys’ fees and costs. The consent decree was entered as a final order in June 2008.
In 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant. In April 2005, TCEQ issued an Executive Director’s Report (Report) recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of approximately $228 thousand against SWEPCo. In 2008, the matter was remanded to TCEQ to pursue settlement discussions. The original Report contained a recommendation to limit the heat input on each Welsh unit to the referenced heat input contained within the state permit within 10 days of the issuance of a final TCEQ order and until the permit is changed. SWEPCo had previously requested a permit alteration to remove the reference to a specific heat input value for each Welsh unit and to clarify the sulfur content requirement for fuels consumed at the plant. A permit alteration was issued in March 2007. In June 2007, TCEQ denied a motion to overturn the permit alteration. The permit alteration was appealed to the Travis County District Court, but was resolved by entry of the consent decree in the federal citizen suit action, and dismissed with prejudice in July 2008. Notice of an administrative settlement of the TCEQ enforcement action was published in June 2008. The settlement requires SWEPCo to pay an administrative penalty of $49 thousand and to fund a supplemental environmental project in the amount of $49 thousand, and resolves all violations alleged by TCEQ. In October 2008, TCEQ approved the settlement.
In February 2008, the Federal EPA issued a Notice of Violation (NOV) based on alleged violations of a percent sulfur in fuel limitation and the heat input values listed in the previous state permit. The NOV also alleges that thea permit alteration issued by TCEQthe Texas Commission on Environmental Quality was improper. SWEPCo met with the Federal EPA to discuss the alleged violations in March 2008. The Federal EPA did not object to the settlement of similar alleged violations in the federal citizen suit.
We are unable to predict the timing of any future action by the Federal EPA or the effect of such actionactions on our net income, cash flows or financial condition.
Carbon Dioxide (CO2) Public Nuisance Claims
In 2004, eight states and the City of New York filed an action in federal district courtFederal District Court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority. The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants. The actions allege that CO2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming, and sought injunctive relief in the form of specific emission reduction commitments from the defendants. The dismissal of this lawsuit was appealed to the Second Circuit Court of Appeals. Briefing and oral argument have concluded.concluded in 2006. In April 2007, the U.S. Supreme Court issued a decision holding that the Federal EPA has authority to regulate emissions of CO2 and other greenhouse gases under the CAA, which may impact the Second Circuit’s analysis of these issues. The Second Circuit requested supplemental briefs addressing the impact of the U.S. Supreme Court’s decision on this case.case which we provided in 2007. We believe the actions are without merit and intend to defend against the claims.
Alaskan Villages’ Claims
In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in federal courtFederal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil & gas companies, a coal company and other electric generating companies. The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together. The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance. The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million. The defendants filed motions to dismiss the action. The motions are pending before the court. We believe the action is without merit and intend to defend against the claims.
Clean Air Act Interstate Rule
In 2005, the Federal EPA issued a final rule, the Clean Air Interstate Rule (CAIR), that required 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). 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 issued a decision that would vacate the CAIR and remand the rule to the Federal EPA. In September 2008, 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.
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 environmental compliance strategy. However, independent obligations under the CAA, including obligations under future state implementation plan submittals, and actions taken pursuant to the settlement of the NSR enforcement action, are consistent with the actions included in a least-cost CAIR compliance plan. Consequently, management does not anticipate making any immediate changes in near-term compliance plans as a result of these court decisions.
The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation
By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, our generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls (PCBs) and other hazardous and nonhazardous materials. We currently incur costs to safely dispose of these substances.
Superfund addresses clean-up of hazardous substances that have been released to the environment. The Federal EPA administers the clean-up programs. Several states have enacted similar laws. In March 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M requested remediation proposals from environmental consulting firms. In May 2008, I&M issued a contract to one of the consulting firms.firms and started remediation work in accordance with a plan approved by MDEQ. I&M recorded approximately $4 million of expense through September 30,during 2008. Based upon updated information, I&M recorded additional expense of $3 million in March 2009. As the remediation work is completed, I&M’s cost may continue to increase. I&M cannot predict the amount of additional cost, if any. At present,
Defective Environmental Equipment
As part of our estimates do not anticipate material cleanupcontinuing environmental investment program, we chose to retrofit wet flue gas desulfurization systems on several of our units utilizing the JBR technology. The retrofits on two units are operational. Due to unexpected operating results, we completed an extensive review of the design and manufacture of the JBR internal components. Our review concluded that there are fundamental design deficiencies and that inferior and/or inappropriate materials were selected for the internal fiberglass components. We initiated discussions with Black & Veatch, the original equipment manufacturer, to develop a repair or replacement corrective action plan. We intend to pursue our contractual and other legal remedies if we are unable to resolve these issues with Black & Veatch. If we are unsuccessful in obtaining reimbursement for the work required to remedy this situation, the cost of repair or replacement could have an adverse impact on construction costs, for this site.net income, cash flows or financial condition.
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 Cook Plant Unit 1 (Unit 1) due to turbine vibrations, likely caused by blade failure, which resulted in a fire on the electric generator. This equipment, islocated in the turbine building, and is separate and isolated from the nuclear reactor. The steam turbinesturbine rotors that caused the vibration were installed in 2006 and are underwithin the vendor’s warranty from the vendor.period. The warranty provides for the repair or replacement of the turbinesturbine rotors if the damage was caused by a defect in the designmaterials or assembly of the turbines.workmanship. I&M is also working with its insurance company, Nuclear Electric Insurance Limited (NEIL), and its turbine vendor, Siemens, to evaluate the extent of the damage resulting from the incident and the costsfacilitate repairs to return the unit to service. We cannot estimate the ultimate costsRepair of the outage at this time.property damage and replacement of the turbine rotors and other equipment could cost up to approximately $330 million. 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 thatThe treatment of property damage costs, replacement power costs and insurance proceeds will be the subject of future regulatory proceedings in Indiana and Michigan. I&M is repairing Unit 1 couldto resume operations as early as late first quarter/early second quarterOctober 2009 at reduced power. Should post-repair operations prove unsuccessful, the replacement of parts will extend the outage into 2011.
The refueling outage scheduled for the fall of 2009 or as late asfor Unit 1 was rescheduled to the second halfspring of 2009, depending upon whether2010. Management anticipates that the damaged components can be repaired or whether they needloss of capacity from Unit 1 will not affect I&M’s ability to be replaced.serve customers due to the existence of sufficient generating capacity in the AEP Power Pool.
I&M maintains property insurance through NEIL with a $1 million deductible. As of March 31, 2009, we recorded $34 million in Prepayments and Other on our Condensed Consolidated Balance Sheets representing recoverable amounts under the property insurance policy. I&M received partial reimbursement from NEIL for the cost incurred to date to repair the property damage. I&M also maintains a separate accidental outage policy with NEIL whereby, after a 12 week12-week deductible period, I&M is entitled to weekly payments of $3.5 million duringfor the first 52 weeks following the deductible period. After the initial 52 weeks of indemnity, the policy pays $2.8 million per week for up to an additional 110 weeks. I&M began receiving payments under the accidental outage period for a covered loss.policy in December 2008. In the first quarter of 2009, I&M recorded $54 million in revenues, including $9 million that were deferred at December 31, 2008, related to the accidental outage policy. In order to hold customers harmless, in the first quarter of 2009, I&M applied $20 million of the accidental outage insurance proceeds to reduce fuel underrecoveries reflecting recoverable fuel costs as if Unit 1 were operating. 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.
TEM Litigation
We agreed to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) (now known as SUEZ Energy Marketing NA, Inc.) for a period of 20 years under a Power Purchase and Sale Agreement (PPA). Beginning May 1, 2003, we tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming.
In 2003, TEM and AEP separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. We alleged that TEM breached the PPA and sought a determination of our rights under the PPA. TEM alleged that the PPA never became enforceable, or alternatively, that the PPA was terminated as the result of our breaches.
In January 2008, we reached a settlement with TEM to resolve all litigation regarding the PPA. TEM paid us $255 million. We recorded the $255 million as a pretax gain in January 2008 under Asset Impairments and Other Related Charges on our Condensed Consolidated Statements of Income. This settlement and the PPA related to the Plaquemine Cogeneration Facility which was impaired andwe sold in 2006.
Enron Bankruptcy
In 2001, we purchased HPLHouston Pipeline Company (HPL) from Enron. Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy. In connection with our acquisition of HPL, we entered into an agreement with BAM Lease Company, which granted HPL the exclusive right to use approximately 55 billion cubic feet (BCF) of cushion gas required for the normal operation of the Bammel gas storage facility. At the time of our acquisition of HPL, BOA and certain other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of the cushion gas. Also at the time of our acquisition, Enron and the BOA Syndicate released HPL from all prior and future liabilities and obligations in connection with the financing arrangement. After the Enron bankruptcy, the BOA Syndicate informed HPL of a purported default by Enron under the terms of the financing arrangement. This dispute is being litigated in the Enron bankruptcy proceedings and in federal courts in Texas and New York.
In February 2004, Enron filed Notices of Rejection regarding the cushion gas exclusive right to use agreement and other incidental agreements. We objected to Enron’s attempted rejection of these agreements and filed an adversary proceeding contesting Enron’s right to reject these agreements.
In 2003, AEP filed a lawsuit against BOA in the United States District Court for the Southern District of Texas. BOA led the lending syndicate involving the monetization of the cushion gas to Enron and its subsidiaries. The lawsuit asserts that BOA made misrepresentations and engaged in fraud to induce and promote the stock sale of HPL, that BOA directly benefited from the sale of HPL and that AEP undertook the stock purchase and entered into the cushion gas arrangement with Enron and BOA based on misrepresentations that BOA made about Enron’s financial condition that BOA knew or should have known were false. In April 2005, the Judge entered an order severing and transferring the declaratory judgment claims involving the right to use and cushion gas consent agreements to the Southern District of New York and retaining in the Southern District of Texas the four counts alleging breach of contract, fraud and negligent misrepresentation in the Southern District of Texas.misrepresentation. HPL and BOA filed motions for summary judgment in the case pending in the Southern District of New York. Trial in federal court in Texas was continued pending a decision on the motions for summary judgment in the New York case.
In August 2007, the judge in the New York action issued a decision granting BOA summary judgment and dismissingdismissed our claims. In December 2007, the judge held that BOA is entitled to recover damages of approximately $347 million ($427 million including interest at December 31, 2007).plus interest. In August 2008, the court entered a final judgment of $346 million (the original judgment less $1 million BOA would have incurred to remove 55 BCF of natural gas from the Bammel storage facility) and clarified the interest calculation method. We appealed and posted a bond covering the amount of the judgment entered against us. The appeal was briefed during the first quarter of 2009. Oral argument remains to be scheduled.
In 2005, we sold our interest in HPL. We indemnified the buyer of HPL against any damages resulting from the BOA litigation up to the purchase price. After recalculation for the final judgment, the liability for the BOA litigation was $431$435 million and $433 million including interest at September 30, 2008. The liability for the BOA litigation was $427 million atMarch 31, 2009 and December 31, 2007.2008, respectively. These liabilities are included in Deferred Credits and Other on our Condensed Consolidated Balance Sheets.
Shareholder Lawsuits
In 2002 and 2003, three putative class action lawsuits were filed in Federal District Court, Columbus, Ohio against AEP, certain executives and AEP’s Employee Retirement Income Security Act (ERISA)ERISA Plan Administrator alleging violations of ERISA in the selection of AEP stock as an investment alternative and in the allocation of assets to AEP stock. The ERISA actions were pending in Federal District Court, Columbus, Ohio. In these actions, the plaintiffs sought recovery of an unstated amount of compensatory damages, attorney fees and costs. Two of the three actions were dropped voluntarily by the plaintiffs in those cases. In July 2006, the court entered judgment in the remaining case, denying the plaintiff’s motion for class certification and dismissing all claims without prejudice. In August 2007, the appeals court reversed the trial court’s decision and held that the plaintiff did have standing to pursue his claim. The appeals court remanded the case to the trial court to consider the issue of whether the plaintiff is an adequate representative for the class of plan participants. In September 2008, the trial court denied the plaintiff’s motion for class certification and ordered briefing on whether the plaintiff may maintain an ERISA claim on behalf of the Plan in the absence of class certification. In October 2008, Counsel forMarch 2009, the plaintiff filedcourt granted a motion to intervene on behalf of an individual seeking to intervene as a new plaintiff. We intend to oppose this motion andwill continue to defend against these claims.
Natural Gas Markets Lawsuits
In 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP (or a subsidiary) is among the companies named as defendants in some of these cases. These cases are at various pre-trial stages. In June 2008, we settled all of the cases pending against us in California state court along with all of the cases brought against us in federal court by plaintiffs in California. The settlements did not impact 2008 earnings due to provisions made in prior periods. We will continue to defend each remaining case where an AEP company is a defendant. We believe the provision we recorded for the remaining provision balancecases is adequate.
Rail Transportation Litigation
In October 2008, the Oklahoma Municipal Power Authority and the Public Utilities Board of the City of Brownsville, Texas, as co-owners of Oklaunion Plant, filed a lawsuit in United States District Court, Western District of Oklahoma against AEP alleging breach of contract and breach of fiduciary duties related to negotiations for rail transportation services for the plant. The plaintiffs allege that AEP tookassumed the dutyduties of the project manager, PSO, and operated the plant for the project manager and is therefore responsible for the alleged breaches. In December 2008, the court denied our motion to dismiss the case. We intend to vigorously defend against these allegations. We believe a provision recorded in 2008 should be sufficient.
FERC Long-term Contracts
In 2002, the FERC held a hearing related to a complaint filed by Nevada Power Company and Sierra Pacific Power Company (the Nevada utilities). The complaint sought to break long-term contracts entered during the 2000 and 2001 California energy price spike which the customers alleged were “high-priced.” The complaint alleged that we sold power at unjust and unreasonable prices because the market for power was allegedly dysfunctional at the time such contracts were executed. In 2003, the FERC rejected the complaint. In 2006, the U.S. Court of Appeals for the Ninth Circuit reversed the FERC order and remanded the case to the FERC for further proceedings. That decision was appealed to the U.S. Supreme Court. In June 2008, the U.S. Supreme Court affirmed the validity of contractually-agreed rates except in cases of serious harm to the public. The U.S. Supreme Court affirmed the Ninth Circuit’s remand on two issues, market manipulation and excessive burden on consumers. Management is unableThe FERC initiated remand procedures and gave the parties time to predictattempt to settle the outcome of these proceedings or their impact on future net income and cash flows.issues. We believe a provision recorded in 2008 should be sufficient. We asserted claims against certain companies that sold power to us, which we resold to the Nevada utilities, seeking to recover a portion of any amounts we may owe to the Nevada utilities.
5. | ACQUISITIONS, DISPOSITIONS AND DISCONTINUED OPERATIONS |
ACQUISITIONS
2008
Erlbacher companies (AEP River Operations segment)
In June 2008, AEP River Operations purchased certain barging assets from Missouri Barge Line Company, Missouri Dry Dock and Repair Company and Cape Girardeau Fleeting, Inc. (collectively known as Erlbacher companies) for $35 million. These assets were incorporated into AEP River Operations’ business which will diversify its customer base.
2007
Darby Electric Generating Station (Utility Operations segment)
In November 2006, CSPCo agreed Management is unable to purchase Darby Electric Generating Station (Darby) from DPL Energy, LLC, a subsidiarypredict the outcome of The Dayton Power and Light Company, for $102 million and the assumption of liabilities of $2 million. CSPCo completed the purchase in April 2007. The Darby plant is located near Mount Sterling, Ohio and is a natural gas, simple cycle power plant with a generating capacity of 480 MW.
Lawrenceburg Generating Station (Utility Operations segment)
In January 2007, AEGCo agreed to purchase Lawrenceburg Generating Station (Lawrenceburg) from an affiliate of Public Service Enterprise Group (PSEG) for $325 million and the assumption of liabilities of $3 million. AEGCo completed the purchase in May 2007. The Lawrenceburg plant is located in Lawrenceburg, Indiana, adjacent to I&M’s Tanners Creek Plant, and is a natural gas, combined cycle power plant with a generating capacity of 1,096 MW. AEGCo sells the power to CSPCo through a FERC-approved unit power agreement.
Dresden Plant (Utility Operations segment)
In August 2007, AEGCo agreed to purchase the partially completed Dresden Plant from Dominion Resources, Inc. for $85 million and the assumption of liabilities of $2 million. AEGCo completed the purchase in September 2007. As of September 30, 2008, AEGCo has incurred approximately $53 million in construction costs (excluding AFUDC) at the Dresden Plant and expects to incur approximately $169 million in additional costs (excluding AFUDC) prior to completion in 2010. The projected completion date of the Dresden Plant is currently under review. To the extent that the completion of the Dresden Plant is delayed, the total projected cost of the Dresden Plant could change. The Dresden Plant is located near Dresden, Ohio and is a natural gas, combined cycle power plant. When completed, the Dresden Plant will have a generating capacity of 580 MW.
DISPOSITIONS
2008
None
2007
Texas Plants – Oklaunion Power Station (Utility Operations segment)
In February 2007, TCC sold its 7.81% share of Oklaunion Power Station to the Public Utilities Board of the City of Brownsville for $43 million plus working capital adjustments. The sale did not have anthese proceedings or their ultimate impact on ourfuture net income nor do we expect any remaining litigation to have a significant effect on our net income.
Intercontinental Exchange, Inc. (ICE) (All Other)
In March 2007, we sold 130,000 shares of ICE and recognized a $16 million pretax gain ($10 million, net of tax). We recorded the gain in Interest and Investment Income on our 2007 Condensed Consolidated Statement of Income. Our remaining investment of approximately 138,000 shares at September 30, 2008 and December 31, 2007 is recorded in Other Temporary Investments on our Condensed Consolidated Balance Sheets.
Texas REPs (Utility Operations segment)
As part of the purchase-and-sale agreement related to the sale of our Texas REPs in 2002, we retained the right to share in earnings with Centrica from the two REPs above a threshold amount through 2006 if the Texas retail market developed increased earnings opportunities. In 2007, we received the final earnings sharing payment of $20 million. This payment is reflected in Gain on Disposition of Assets, Net on our Condensed Consolidated Statement of Income.
Sweeny Cogeneration Plant (Generation and Marketing segment)
In October 2007, we sold our 50% equity interest in the Sweeny Cogeneration Plant (Sweeny) to ConocoPhillips for approximately $80 million, including working capital and the buyer’s assumption of project debt. The Sweeny Cogeneration Plant is a 480 MW cogeneration plant located within ConocoPhillips’ Sweeny refinery complex southwest of Houston, Texas. We were the managing partner of the plant, which is co-owned by General Electric Company. As a result of the sale, we recognized a $47 million pretax gain ($30 million, net of tax) in the fourth quarter of 2007, which is reflected in Gain on Disposition of Equity Investments, Net on our 2007 Consolidated Statement of Income.
In addition to the sale of our interest in Sweeny, we agreed to separately sell our purchase power contract for our share of power generated by Sweeny through 2014 for $11 million to ConocoPhillips. ConocoPhillips also agreed to assume certain related third-party power obligations. These transactions were completed in conjunction with the sale of our 50% equity interest in October 2007. As a result of this sale, we recognized an $11 million pretax gain ($7 million, net of tax) in the fourth quarter of 2007, which is included in Other revenues on our 2007 Consolidated Statement of Income. In the fourth quarter of 2007, we recognized a total of $58 million in pretax gains ($37 million, net of tax).
DISCONTINUED OPERATIONS
We determined that certain of our operations were discontinued operations and classified them as such for all periods presented. We recorded the following in 2008 and 2007 related to discontinued operations:
| | U.K.
Generation (a)
| |
Three Months Ended September 30, | | (in millions) | |
2008 Revenue | | $ | - | |
2008 Pretax Income | | | - | |
2008 Earnings, Net of Tax | | | - | |
| | | | |
2007 Revenue | | $ | - | |
2007 Pretax Income | | | - | |
2007 Earnings, Net of Tax | | | - | |
| | U.K.
Generation (a)
| |
Nine Months Ended September 30, | | (in millions) | |
2008 Revenue | | $ | - | |
2008 Pretax Income | | | 2 | |
2008 Earnings, Net of Tax | | | 1 | |
| | | | |
2007 Revenue | | $ | - | |
2007 Pretax Income | | | 3 | |
2007 Earnings, Net of Tax | | | 2 | |
(a) | The 2008 amounts relate to final proceeds received for the sale of land related to the sale of U.K. Generation. The 2007 amounts relate to tax adjustments from the sale of U.K. Generation. |
There were no cash flows used for or provided by operating, investing or financing activities related to our discontinued operations for the nine months ended September 30, 2008 and 2007.flows.
6.5. BENEFIT PLANS
Components of Net Periodic Benefit Cost
The following tables providetable provides the components of our net periodic benefit cost for the plans for the three and nine months ended September 30, 2008March 31, 2009 and 2007:2008:
| | | Other Postretirement | |
| Pension Plans | | Benefit Plans | |
| Three Months Ended September 30, | | Three Months Ended September 30, | |
| 2008 | | 2007 | | 2008 | | 2007 | |
| (in millions) | |
Service Cost | | $ | 25 | | | $ | 24 | | | $ | 10 | | | $ | 11 | |
Interest Cost | | | 62 | | | | 59 | | | | 28 | | | | 26 | |
Expected Return on Plan Assets | | | (84 | ) | | | (85 | ) | | | (27 | ) | | | (26 | ) |
Amortization of Transition Obligation | | | - | | | | - | | | | 7 | | | | 6 | |
Amortization of Net Actuarial Loss | | | 10 | | | | 15 | | | | 3 | | | | 3 | |
Net Periodic Benefit Cost | | $ | 13 | | | $ | 13 | | | $ | 21 | | | $ | 20 | |
| | | | Other | |
| | | Other Postretirement | | | | Postretirement | |
| Pension Plans | | Benefit Plans | | Pension Plans | | Benefit Plans | |
| Nine Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended March 31, | | Three Months Ended March 31, | |
| 2008 | | 2007 | | 2008 | | 2007 | | 2009 | | 2008 | | 2009 | | 2008 | |
| (in millions) | | (in millions) | |
Service Cost | | $ | 75 | | | $ | 72 | | | $ | 31 | | | $ | 32 | | | $ | 26 | | | $ | 25 | | | $ | 10 | | | $ | 10 | |
Interest Cost | | | 187 | | | | 176 | | | | 84 | | | | 78 | | | | 63 | | | | 63 | | | | 27 | | | | 28 | |
Expected Return on Plan Assets | | | (252 | ) | | | (254 | ) | | | (83 | ) | | | (78 | ) | | | (80 | ) | | | (84 | ) | | | (20 | ) | | | (28 | ) |
Amortization of Transition Obligation | | | - | | | | - | | | | 21 | | | | 20 | | | | - | | | | - | | | | 7 | | | | 7 | |
Amortization of Net Actuarial Loss | | | 29 | | | | 44 | | | | 8 | | | | 9 | | | | 15 | | | | 9 | | | | 11 | | | | 3 | |
Net Periodic Benefit Cost | | $ | 39 | | | $ | 38 | | | $ | 61 | | | $ | 61 | | | $ | 24 | | | $ | 13 | | | $ | 35 | | | $ | 20 | |
We havesponsor several trust funds with significant investments in several trust fundsintended to provide for future pension and OPEB payments. 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 from the December 31, 2008 balances due to the decreases in the equity and fixed income markets. Although the asset values are currently lower than at year end, this decline has not affected the funds’ ability to make their required payments.
As outlined in our 20072008 Annual Report, our primary business strategy and the core of our business are to focus onis our electric utility operations. Within our Utility Operations segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Generation/supply in Ohio continues to have commission-determined rates transitioning from cost-based to market-based rates. The legislature in Ohio is currently considering possibly returning to some form of cost-based rate-regulation or a hybrid form of rate-regulation for generation. While our Utility Operations segment remains our primary business segment, other segments include our AEP River Operations segment with significant barging activities and our Generation and Marketing segment, which includes our nonregulated generating, marketing and risk management activities primarily in the ERCOT market area. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements.
Our reportable segments and their related business activities are as follows:
Utility Operations
· | Generation of electricity for sale to U.S. retail and wholesale customers. |
· | Electricity transmission and distribution in the U.S. |
AEP River Operations
· | Commercial Barging operations that annually transport approximately 3533 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers. Approximately 39%38% of the barging is for transportation of agricultural products, 30% for coal, 14%13% for steel and 17%19% for other commodities. Effective July 30, 2008, AEP MEMCO LLC’s name was changed to AEP River Operations LLC. |
Generation and Marketing
· | Wind farms and marketing and risk management activities primarily in ERCOT. |
The remainder of our activities is presented as All Other. While not considered a business segment, All Other includes:
· | Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. |
· | Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005. These contracts are financial derivatives which will gradually liquidate and completely expire in 2011. |
· | The first quarter 2008 cash settlement of a purchase power and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006. |
· | Revenue sharing related to the Plaquemine Cogeneration Facility. |
The tables below present our reportable segment information for the three and nine months ended September 30,March 31, 2009 and 2008 and 2007 and balance sheet information as of September 30, 2008March 31, 2009 and December 31, 2007.2008. These amounts include certain estimates and allocations where necessary. We reclassified prior year amounts to conform to the current year’s segment presentation. See “FSP FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1)” section of Note 2 for discussion of changes in netting certain balance sheet amounts.
| | | | Nonutility Operations | | | | | | | |
| | Utility Operations | | AEP River Operations | | Generation and Marketing | | All Other (a) | | Reconciling Adjustments | | Consolidated | |
| | (in millions) |
Three Months Ended September 30, 2008 | | | | | | | | | | | | | | | | | | | |
Revenues from: | | | | | | | | | | | | | | | | | | | |
External Customers | | $ | 4,108 | (d) | $ | 160 | | $ | 1 | | $ | (78 | ) | $ | - | | $ | 4,191 | |
Other Operating Segments | | | (140 | )(d) | | 7 | | | 95 | | | 83 | | | (45 | ) | | - | |
Total Revenues | | $ | 3,968 | | $ | 167 | | $ | 96 | | $ | 5 | | $ | (45 | ) | $ | 4,191 | |
| | | | | | | | | | | | | | | | | | | |
Income (Loss) Before Discontinued Operations and Extraordinary Loss | | $ | 357 | | $ | 11 | | $ | 16 | | $ | (10 | ) | $ | - | | $ | 374 | |
Discontinued Operations, Net of Tax | | | - | | | - | | | - | | | - | | | - | | | - | |
Net Income (Loss) | | $ | 357 | | $ | 11 | | $ | 16 | | $ | (10 | ) | $ | - | | $ | 374 | |
| | | | Nonutility Operations | | | | | | | |
| | Utility Operations | | AEP River Operations | | Generation and Marketing | | All Other (a) | | Reconciling Adjustments | | Consolidated | |
| | (in millions) |
Three Months Ended September 30, 2007 | | | | | | | | | | | | | | | | | | | |
Revenues from: | | | | | | | | | | | | | | | | | | | |
External Customers | | $ | 3,423 | (d) | $ | 134 | | $ | 241 | | $ | (9 | ) | $ | - | | $ | 3,789 | |
Other Operating Segments | | | 177 | (d) | | 4 | | | (161 | ) | | 19 | | | (39 | ) | | - | |
Total Revenues | | $ | 3,600 | | $ | 138 | | $ | 80 | | $ | 10 | | $ | (39 | ) | $ | 3,789 | |
| | | | | | | | | | | | | | | | | | | |
Net Income (Loss) | | $ | 388 | | $ | 18 | | $ | 3 | | $ | (2 | ) | $ | - | | $ | 407 | |
| | | | Nonutility Operations | | | | | | | | | | | | | Nonutility Operations | | | | | | | | | | |
| | Utility Operations | | AEP River Operations | | Generation and Marketing | | All Other (a) | | Reconciling Adjustments | | Consolidated | | | Utility Operations | | | | AEP River Operations | | | Generation and Marketing | | | All Other (a) | | | Reconciling Adjustments | | | Consolidated | |
| | (in millions) | | (in millions) | |
Nine Months Ended September 30, 2008 | | | | | | | | | | | | | | | |
Three Months Ended March 31, 2009 | | | | | | | | | | | | | | | | | | | | |
Revenues from: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
External Customers | | $ | 10,318 | (d) | $ | 442 | | $ | 409 | | $ | 35 | | $ | - | | $ | 11,204 | | | $ | 3,267 | | (d) | | $ | 123 | | | $ | 87 | | | $ | (19 | ) | | $ | - | | | $ | 3,458 | |
Other Operating Segments | | | 257 | (d) | | 18 | | | (143 | ) | | (17 | ) | | (115 | ) | | - | | | | - | | (d) | | | 6 | | | | 5 | | | | 22 | | | | (33 | ) | | | - | |
Total Revenues | | $ | 10,575 | | $ | 460 | | $ | 266 | | $ | 18 | | $ | (115 | ) | $ | 11,204 | | | $ | 3,267 | | | | $ | 129 | | | $ | 92 | | | $ | 3 | | | $ | (33 | ) | | $ | 3,458 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Income Before Discontinued Operations and Extraordinary Loss | | $ | 1,030 | | $ | 21 | | $ | 43 | | $ | 133 | | $ | - | | $ | 1,227 | | |
Discontinued Operations, Net of Tax | | | - | | | - | | | - | | | 1 | | | - | | | 1 | | |
Net Income | | $ | 1,030 | | $ | 21 | | $ | 43 | | $ | 134 | | $ | - | | $ | 1,228 | | |
Net Income (Loss) | | | $ | 346 | | | | $ | 11 | | | $ | 24 | | | $ | (18 | ) | | $ | - | | | $ | 363 | |
Less: Net Income Attributable to Noncontrolling Interests | | | | (2 | ) | | | | - | | | | - | | | | - | | | | - | | | | (2 | ) |
Net Income (Loss) Attributable to AEP Shareholders | | | | 344 | | | | | 11 | | | | 24 | | | | (18 | ) | | | - | | | | 361 | |
Less: Preferred Stock Dividend Requirements of Subsidiaries | | | | (1 | ) | | | | - | | | | - | | | | - | | | | - | | | | (1 | ) |
Earnings (Loss) Attributable to AEP Common Shareholders | | | $ | 343 | | | | $ | 11 | | | $ | 24 | | | $ | (18 | ) | | $ | - | | | $ | 360 | |
| | | | Nonutility Operations | | | | | | | |
| | Utility Operations | | AEP River Operations | | Generation and Marketing | | All Other (a) | | Reconciling Adjustments | | Consolidated | |
| | (in millions) |
Nine Months Ended September 30, 2007 | | | | | | | | | | | | | | | | | | | |
Revenues from: | | | | | | | | | | | | | | | | | | | |
| External Customers | | $ | 9,127 | (d) | $ | 367 | | $ | 574 | | $ | 36 | | $ | - | | $ | 10,104 | |
| Other Operating Segments | | | 460 | (d) | | 10 | | | (347 | ) | | (14 | ) | | (109 | ) | | - | |
Total Revenues | | $ | 9,587 | | $ | 377 | | $ | 227 | | | 22 | | | (109 | ) | $ | 10,104 | |
| | | | | | | | | | | | | | | | | | | |
Income (Loss) Before Discontinued Operations and Extraordinary Loss | | $ | 879 | | $ | 40 | | $ | 17 | | $ | (1 | ) | $ | - | | $ | 935 | |
Discontinued Operations, Net of Tax | | | - | | | - | | | - | | | 2 | | | - | | | 2 | |
Extraordinary Loss, Net of Tax | | | (79 | ) | | - | | | - | | | - | | | - | | | (79 | ) |
Net Income | | $ | 800 | | $ | 40 | | $ | 17 | | $ | 1 | | $ | - | | $ | 858 | |
| | | | | | Nonutility Operations | | | | | | | | | | |
| | Utility Operations | | | | AEP River Operations | | | Generation and Marketing | | | All Other (a) | | | Reconciling Adjustments | | | Consolidated | |
| | (in millions) | |
Three Months Ended March 31, 2008 | | | | | | | | | | | | | | | | | | | |
Revenues from: | | | | | | | | | | | | | | | | | | | |
External Customers | | $ | 3,010 | | (d) | | $ | 138 | | | $ | 271 | | | $ | 48 | | | $ | - | | | $ | 3,467 | |
Other Operating Segments | | | 284 | | (d) | | | 4 | | | | (212 | ) | | | (43 | ) | | | (33 | ) | | | - | |
Total Revenues | | $ | 3,294 | | | | $ | 142 | | | $ | 59 | | | $ | 5 | | | $ | (33 | ) | | $ | 3,467 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Net Income | | $ | 413 | | | | $ | 7 | | | $ | 1 | | | $ | 155 | | | $ | - | | | $ | 576 | |
Less: Net Income Attributable to Noncontrolling Interests | | | (2 | ) | | | | - | | | | - | | | | - | | | | - | | | | (2 | ) |
Net Income Attributable to AEP Shareholders | | | 411 | | | | | 7 | | | | 1 | | | | 155 | | | | - | | | | 574 | |
Less: Preferred Stock Dividend Requirements of Subsidiaries | | | (1 | ) | | | | - | | | | - | | | | - | | | | - | | | | (1 | ) |
Earnings Attributable to AEP Common Shareholders | | $ | 410 | | | | $ | 7 | | | $ | 1 | | | $ | 155 | | | $ | - | | | $ | 573 | |
| | | | Nonutility Operations | | | | | | | |
| | Utility Operations | | AEP River Operations | | Generation and Marketing | | All Other (a) | | Reconciling Adjustments (c) | | Consolidated | |
| | (in millions) | |
September 30, 2008 | | | | | | | | | | | | | | | | | | | |
Total Property, Plant and Equipment | | $ | 47,699 | | $ | 316 | | $ | 577 | | $ | 45 | | $ | (245 | ) | $ | 48,392 | |
Accumulated Depreciation and Amortization | | | 16,413 | | | 69 | | | 133 | | | 8 | | | (20 | ) | | 16,603 | |
Total Property, Plant and Equipment – Net | | $ | 31,286 | | $ | 247 | | $ | 444 | | $ | 37 | | $ | (225 | ) | $ | 31,789 | |
| | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 41,322 | | $ | 380 | | $ | 771 | | $ | 13,905 | | $ | (13,340 | )(b) | $ | 43,038 | |
| | | | | Nonutility Operations | | | | | | | | | | | |
| | Utility Operations | | | AEP River Operations | | | Generation and Marketing | | | All Other (a) | | | Reconciling Adjustments (c) | | | | Consolidated | |
| | (in millions) | |
March 31, 2009 | | | | | | | | | | | | | | | | | | | |
Total Property, Plant and Equipment | | $ | 49,454 | | | $ | 368 | | | $ | 570 | | | $ | 10 | | | $ | (238 | ) | | | $ | 50,164 | |
Accumulated Depreciation and Amortization | | | 16,708 | | | | 76 | | | | 147 | | | | 8 | | | | (26 | ) | | | | 16,913 | |
Total Property, Plant and Equipment – Net | | $ | 32,746 | | | $ | 292 | | | $ | 423 | | | $ | 2 | | | $ | (212 | ) | | | $ | 33,251 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 44,278 | | | $ | 416 | | | $ | 795 | | | $ | 14,729 | | | $ | (14,353 | ) | (b) | | $ | 45,865 | |
| | | | Nonutility Operations | | | | | | | |
| | Utility Operations | | AEP River Operations | | Generation and Marketing | | All Other (a) | | Reconciling Adjustments (c) | | Consolidated | |
December 31, 2007 | | (in millions) | |
Total Property, Plant and Equipment | | $ | 45,514 | | $ | 263 | | $ | 567 | | $ | 38 | | $ | (237 | ) | $ | 46,145 | |
Accumulated Depreciation and Amortization | | | 16,107 | | | 61 | | | 112 | | | 7 | | | (12 | ) | | 16,275 | |
Total Property, Plant and Equipment – Net | | $ | 29,407 | | $ | 202 | | $ | 455 | | $ | 31 | | $ | (225 | ) | $ | 29,870 | |
| | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 39,298 | | $ | 340 | | $ | 697 | | $ | 12,117 | | $ | (12,133 | )(b) | $ | 40,319 | |
| | | | Nonutility Operations | | | | | | | | | |
| | Utility Operations | | AEP River Operations | | Generation and Marketing | | All Other (a) | | | Reconciling Adjustment (c) | | | Consolidated | |
December 31, 2008 | | (in millions) | |
Total Property, Plant and Equipment | | | $ | 48,997 | | | $ | 371 | | | $ | 565 | | | $ | 10 | | | $ | (233 | ) | | | $ | 49,710 | |
Accumulated Depreciation and Amortization | | | | 16,525 | | | | 73 | | | | 140 | | | | 8 | | | | (23 | ) | | | | 16,723 | |
Total Property, Plant and Equipment – Net | | | $ | 32,472 | | | $ | 298 | | | $ | 425 | | | $ | 2 | | | $ | (210 | ) | | | $ | 32,987 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Assets | | | $ | 43,773 | | | $ | 439 | | | $ | 737 | | | $ | 14,501 | | | $ | (14,295 | ) | (b) | | $ | 45,155 | |
(a) | All Other includes: |
| · | Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. |
| · | Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005. These contracts are financial derivatives which will gradually liquidate and completely expire in 2011. |
| · | The first quarter 2008 cash settlement of a purchase power and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in the fourth quarter of 2006. The cash settlement of $255 million ($163164 million, net of tax) is included in Net Income. |
| · | Revenue sharing related to the Plaquemine Cogeneration Facility. |
(b) | Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. |
(c) | Includes eliminations due to an intercompany capital lease. |
(d) | PSO and SWEPCo transferred certain existing ERCOT energy marketing contracts to AEP Energy Partners, Inc. (AEPEP) (Generation and Marketing segment) and entered into intercompany financial and physical purchase and sales agreements with AEPEP. As a result, we reported third-party net purchases or sales activity for these energy marketing contracts as Revenues from External Customers for the Utility Operations segment. This is offset by the Utility Operations segment’s related net sales (purchases) for these contracts towith AEPEP in Revenues from Other Operating Segments of $(95)$(5) million and $161$212 million for the three months ended September 30,March 31, 2009 and 2008, and 2007, respectively, and $143 million and $347 million for the nine months ended September 30, 2008 and 2007, respectively. The Generation and Marketing segment also reports these purchase or sales contracts with Utility Operations as Revenues from Other Operating Segments. These affiliated contracts between PSO and SWEPCo with AEPEP will end in December 2009. |
7. DERIVATIVES, HEDGING AND FAIR VALUE MEASUREMENTS
DERIVATIVES AND HEDGING
Objectives for Utilization of Derivative Instruments
We are 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, credit risk and to a lesser extent foreign currency exchange risk. These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates. We manage these risk using derivative instruments.
Strategies for Utilization of Derivative Instruments to Achieve Objectives
Our strategy surrounding the use of derivative instruments focuses on managing our risk exposures, future cash flows and creating value based on our open trading positions by utilizing both economic and formal SFAS 133 hedging strategies. To accomplish our objectives, we primarily employ risk management contracts including physical forward purchase and sale contracts, financial forward purchase and sale contracts and financial swap instruments. Not all risk management contracts meet the definition of a derivative under SFAS 133. Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of SFAS 133.
We enter into electricity, coal, natural gas, interest rate and to a lesser degree heating oil, gasoline, emission allowance and other commodity contracts to manage the risk associated with our energy business. We enter into interest rate derivative contracts in order to manage the interest rate exposure associated with our commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as they are related to energy risk management activities. We also engage in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of AEP’s Board of Directors.
The following table represents the gross notional volume of our outstanding derivative contracts as of March 31, 2009:
Notional Volume of Derivative Instruments |
March 31, 2009 |
| | | | | Unit of |
Primary Risk Exposure | | Volume | | Measure |
| | (in millions) | |
Commodity: | | | | | |
Power | | | 351 | | MWHs |
Coal | | | 51 | | Tons |
Natural Gas | | | 211 | | MMBtu |
Heating Oil and Gasoline | | | 4 | | Gallons |
Interest Rate | | $ | 413 | | USD |
| | | | | |
Interest Rate and Foreign Currency | | $ | 501 | | USD |
Fair Value Hedging Strategies
At certain times, we enter into interest rate derivative transactions in order to manage existing fixed interest rate risk exposure. These interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our fixed-rate debt to a floating rate. Currently, this strategy is not actively employed.
Cash Flow Hedging Strategies
We enter into and designate as cash flow hedges certain derivative transactions for the purchase and sale of electricity, coal and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. We monitor the potential impacts of commodity price changes and, where appropriate, enter into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases. We do not hedge all commodity price risk.
Our vehicle fleet is exposed to gasoline and diesel fuel price volatility. We enter into financial gasoline and heating oil derivative contracts in order to mitigate price risk of our future fuel purchases. We do not hedge all of our fuel price risk. For disclosure purposes, these contracts are included with other hedging activity as “Commodity.”
We enter into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our floating-rate debt to a fixed rate. We also enter into interest rate derivative contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt. Our anticipated fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. We do not hedge all interest rate exposure.
At times, we are exposed to foreign currency exchange rate risks primarily when we purchase certain fixed assets from foreign suppliers. In accordance with our risk management policy, we may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. We do not hedge all foreign currency exposure.
Accounting for Derivative Instruments and the Impact on Our Financial Statements
SFAS 133 requires recognition of all qualifying derivative instruments as either assets or liabilities in the balance sheet at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of our derivative instruments, we also apply valuation adjustments for discounting, liquidity and credit quality.
Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with our estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of our risk management contracts.
According to FSP FIN 39-1, we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the March 31, 2009 and December 31, 2008 balance sheets, we netted $74 million and $11 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $117 million and $43 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.
The following table represents the gross fair value impact of our derivative activity on our Condensed Consolidated Balance Sheet as of March 31, 2009.
Fair Value of Derivative Instruments March 31, 2009 | |
| | Risk Management | | | | | | | | | |
| | Contracts | | Hedging Contracts | | | | | |
| | | | | | Interest Rate | | | | | |
| | | | | | and Foreign | | Other | | | |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Currency | | (b) | | Total | |
| | (in millions) | |
Current Risk Management Assets | | | $ | 2,209 | | | $ | 47 | | | $ | 1 | | | $ | (1,964 | ) | | $ | 293 | |
Long-Term Risk Management Assets | | | | 1,087 | | | | 2 | | | | - | | | | (672 | ) | | | 417 | |
Total Assets | | | | 3,296 | | | | 49 | | | | 1 | | | | (2,636 | ) | | | 710 | |
| | | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | | | | 2,121 | | | | 35 | | | | 4 | | | | (1,981 | ) | | | 179 | |
Long-Term Risk Management Liabilities | | | | 902 | | | | 1 | | | | 4 | | | | (733 | ) | | | 174 | |
Total Liabilities | | | | 3,023 | | | | 36 | | | | 8 | | | | (2,714 | ) | | | 353 | |
| | | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | | $ | 273 | | | $ | 13 | | | $ | (7 | ) | | $ | 78 | | | $ | 357 | |
(a) | Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented in the Condensed Consolidated Balance Sheet on a net basis in accordance with FIN 39 “Offsetting of Amounts Related to Certain Contracts.” |
(b) | Amounts represent counterparty netting of risk management contracts, associated cash collateral in accordance with FSP FIN 39-1 and dedesignated risk management contracts. |
The table below presents our MTM activity of derivative risk management contracts for the three months ended March 31, 2009:
Amount of Gain (Loss) Recognized on Risk Management Contracts |
For the Three Months Ended March 31, 2009 |
Location of Gain (Loss) | | (in millions) | |
Utility Operations Revenue | | $ | 65 | |
Other Revenue | | | 13 | |
Regulatory Assets | | | (1 | ) |
Regulatory Liabilities | | | 74 | |
Total Gain on Risk Management Contracts | | $ | 151 | |
Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in SFAS 133. Derivative contracts that have been designated as normal purchases or normal sales under SFAS 133 are not subject to MTM accounting treatment and are recognized in the Condensed Consolidated Statements of Income on an accrual basis.
Our accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, we designate a hedging instrument as a fair value hedge or a cash flow hedge.
For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in Revenues on a net basis in the Condensed Consolidated Statements of Income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in Revenues or Expenses on the Condensed Consolidated Statements of Income depending on the relevant facts and circumstances. However, unrealized and realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with SFAS 71.
Accounting for Fair Value Hedging Strategies
For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change.
We record realized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged, in Interest Expense on our Condensed Consolidated Statements of Income. During the three months ended March 31, 2009, we did not employ any fair value hedging strategies. During the three months ended March 31, 2008, we designated interest rate derivatives as fair value hedges and did not recognize any hedge ineffectiveness related to these derivative transactions.
Accounting for Cash Flow Hedging Strategies
For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets until the period the hedged item affects Net Income. We recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).
Realized gains and losses on derivative contracts for the purchase and sale of electricity, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale in our Condensed Consolidated Statements of Income, depending on the specific nature of the risk being hedged. We do not hedge all variable price risk exposure related to commodities. During the three months ended March 31, 2009 and 2008, we recognized immaterial amounts in Net Income related to hedge ineffectiveness.
Beginning in 2009, we executed financial heating oil and gasoline derivative contracts to hedge the price risk of our diesel fuel and gasoline purchases. We reclassify gains and losses on financial fuel derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets into Other Operation and Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our Condensed Consolidated Statements of Income. We do not hedge all fuel price risk exposure. During the three months ended March 31, 2009, we recognized no hedge ineffectiveness related to this hedge strategy.
We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) into Interest Expense in those periods in which hedged interest payments occur. During the three months ended March 31, 2009 and 2008, we recognized immaterial amounts in Net Income related to hedge ineffectiveness.
The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets into Depreciation and Amortization expense in our Condensed Consolidated Statements of Income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. We do not hedge all foreign currency exposure. During the three months ended March 31, 2009 and 2008, we recognized no hedge ineffectiveness related to this hedge strategy.
The following table provides details on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for changes in cash flow hedges from January 1, 2009 to March 31, 2009. All amounts in the following table are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | |
For the Three Months Ended March 31, 2009 | |
| | Commodity | | | Interest Rate and Foreign Currency | | | Total | |
| | (in millions) | |
Beginning Balance in AOCI as of January 1, 2009 | | $ | 7 | | | $ | (29 | ) | | $ | (22 | ) |
Changes in Fair Value Recognized in AOCI | | | (3 | ) | | | - | | | | (3 | ) |
Amount of (Gain) or Loss Reclassified from AOCI to Income Statement/within Balance Sheet | | | | | | | | | | | | |
Utility Operations Revenue | | | (2 | ) | | | - | | | | (2 | ) |
Other Revenue | | | (2 | ) | | | - | | | | (2 | ) |
Purchased Electricity for Resale | | | 8 | | | | - | | | | 8 | |
Interest Expense | | | - | | | | 1 | | | | 1 | |
Regulatory Assets | | | 2 | | | | - | | | | 2 | |
Regulatory Liabilities | | | (1 | ) | | | - | | | | (1 | ) |
Ending Balance in AOCI as of March 31, 2009 | | $ | 9 | | | $ | (28 | ) | | $ | (19 | ) |
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheet at March 31, 2009 were:
Impact of Cash Flow Hedges on our Condensed Consolidated Balance Sheet | |
| Commodity | | Interest Rate and Foreign Currency | | Total | |
| (in millions) | |
Hedging Assets (a) | | $ | 40 | | | $ | 1 | | | $ | 41 | |
Hedging Liabilities (a) | | | (27 | ) | | | (8 | ) | | | (35 | ) |
AOCI Gain (Loss) Net of Tax | | | 9 | | | | (28 | ) | | | (19 | ) |
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | | | 8 | | | | (6 | ) | | | 2 | |
(a) | Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on our Condensed Consolidated Balance Sheet. |
The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. As of March 31, 2009, the maximum length of time that we are hedging (with SFAS 133 designated contracts) our exposure to variability in future cash flows related to forecasted transactions is 44 months.
Credit Risk
We limit credit risk in our wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. We use Moody’s, S&P and current market-based qualitative and quantitative data to assess the financial health of counterparties on an ongoing basis. If an external rating is not available, an internal rating is generated utilizing a quantitative tool developed by Moody’s to estimate probability of default that corresponds to an implied external agency credit rating.
We use standardized master agreements which may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit, and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds our established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with our credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
Collateral Triggering Events
Under a limited number of derivative and non-derivative counterparty contracts primarily related to our pre-2002 risk management activities and under the tariffs of the RTOs and Independent System Operators (ISOs), we are obligated to post an amount of collateral if our credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and our total exposure. On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts. We believe that a downgrade below investment grade is unlikely. As of March 31, 2009, the aggregate value of such contracts was $127 million and AEP was not required to post any collateral. We would have been required to post $127 million of collateral at March 31, 2009, if our credit ratings had declined below investment grade of which $123 million was attributable to our RTO and ISO activities.
FAIR VALUE MEASUREMENTS
SFAS 157 Fair Value Measurements
As described in our 2008 Annual Report, SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The Derivatives, Hedging and Fair Value Measurements note within the 2008 Annual Report should be read in conjunction with this report.
The following tables set forth by level, within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2009 and December 31, 2008. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of March 31, 2009 | |
| | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in millions) | |
| | | | | | | | | | | | | | | |
Cash and Cash Equivalents | | | | | | | | | | | | | | | |
Cash and Cash Equivalents (a) | | $ | 637 | | | $ | - | | | $ | - | | | $ | 58 | | | $ | 695 | |
Debt Securities (b) | | | - | | | | 15 | | | | - | | | | - | | | | 15 | |
Total Cash and Cash Equivalents | | | 637 | | | | 15 | | | | - | | | | 58 | | | | 710 | |
| | | | | | | | | | | | | | | | | | | | |
Other Temporary Investments | | | |
Cash and Cash Equivalents (a) | | | 107 | | | | - | | | | - | | | | 27 | | | | 134 | |
Debt Securities (c) | | | 56 | | | | - | | | | - | | | | - | | | | 56 | |
Equity Securities (d) | | | 25 | | | | - | | | | - | | | | - | | | | 25 | |
Total Other Temporary Investments | | | 188 | | | | - | | | | - | | | | 27 | | | | 215 | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (e) | | | 71 | | | | 3,112 | | | | 99 | | | | (2,648 | ) | | | 634 | |
Cash Flow Hedges (e) | | | 8 | | | | 41 | | | | - | | | | (8 | ) | | | 41 | |
Dedesignated Risk Management Contracts (f) | | | - | | | | - | | | | - | | | | 35 | | | | 35 | |
Total Risk Management Assets | | | 79 | | | | 3,153 | | | | 99 | | | | (2,621 | ) | | | 710 | |
| | | | | | | | | | | | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | | | | | | | | | | | |
Cash and Cash Equivalents (g) | | | - | | | | 15 | | | | - | | | | 9 | | | | 24 | |
Debt Securities (h) | | | - | | | | 764 | | | | - | | | | - | | | | 764 | |
Equity Securities (d) | | | 419 | | | | - | | | | - | | | | - | | | | 419 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | | | 419 | | | | 779 | | | | - | | | | 9 | | | | 1,207 | |
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 1,323 | | | $ | 3,947 | | | $ | 99 | | | $ | (2,527 | ) | | $ | 2,842 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (e) | | $ | 86 | | | $ | 2,910 | | | $ | 13 | | | $ | (2,691 | ) | | $ | 318 | |
Cash Flow Hedges (e) | | | 3 | | | | 40 | | | | - | | | | (8 | ) | | | 35 | |
Total Risk Management Liabilities | | $ | 89 | | | $ | 2,950 | | | $ | 13 | | | $ | (2,699 | ) | | $ | 353 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of December 31, 2008 | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in millions) | |
| | | | | | | | | | | | | | | |
Cash and Cash Equivalents | | | | | | | | | | | | | | | |
Cash and Cash Equivalents (a) | | $ | 304 | | | $ | - | | | $ | - | | | $ | 60 | | | $ | 364 | |
Debt Securities (b) | | | - | | | | 47 | | | | - | | | | - | | | | 47 | |
Total Cash and Cash Equivalents | | | 304 | | | | 47 | | | | - | | | | 60 | | | | 411 | |
| | | | | | | | | | | | | | | | | | | | |
Other Temporary Investments | | | |
Cash and Cash Equivalents (a) | | | 217 | | | | - | | | | - | | | | 26 | | | | 243 | |
Debt Securities (c) | | | 56 | | | | - | | | | - | | | | - | | | | 56 | |
Equity Securities (d) | | | 28 | | | | - | | | | - | | | | - | | | | 28 | |
Total Other Temporary Investments | | | 301 | | | | - | | | | - | | | | 26 | | | | 327 | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (e) | | | 61 | | | | 2,413 | | | | 86 | | | | (2,022 | ) | | | 538 | |
Cash Flow Hedges (e) | | | 6 | | | | 32 | | | | - | | | | (4 | ) | | | 34 | |
Dedesignated Risk Management Contracts (f) | | | - | | | | - | | | | - | | | | 39 | | | | 39 | |
Total Risk Management Assets | | | 67 | | | | 2,445 | | | | 86 | | | | (1,987 | ) | | | 611 | |
| | | | | | | | | | | | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | | | | | | | | | | | |
Cash and Cash Equivalents (g) | | | - | | | | 6 | | | | - | | | | 12 | | | | 18 | |
Debt Securities (h) | | | - | | | | 773 | | | | - | | | | - | | | | 773 | |
Equity Securities (d) | | | 469 | | | | - | | | | - | | | | - | | | | 469 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | | | 469 | | | | 779 | | | | - | | | | 12 | | | | 1,260 | |
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 1,141 | | | $ | 3,271 | | | $ | 86 | | | $ | (1,889 | ) | | $ | 2,609 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (e) | | $ | 77 | | | $ | 2,213 | | | $ | 37 | | | $ | (2,054 | ) | | $ | 273 | |
Cash Flow Hedges (e) | | | 1 | | | | 34 | | | | - | | | | (4 | ) | | | 31 | |
Total Risk Management Liabilities | | $ | 78 | | | $ | 2,247 | | | $ | 37 | | | $ | (2,058 | ) | | $ | 304 | |
(a) | Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investments in money market funds. |
(b) | Amount represents commercial paper investments with maturities of less than ninety days. |
(c) | Amounts represent debt-based mutual funds. |
(d) | Amount represents publicly traded equity securities and equity-based mutual funds. |
(e) | Amounts in “Other” column primarily represent counterparty netting of risk management contracts and associated cash collateral under FSP FIN 39-1. |
(f) | “Dedesignated Risk Management Contracts” are contracts that were originally MTM but were subsequently elected as normal under SFAS 133. At the time of the normal election, the MTM value was frozen and no longer fair valued. This MTM value will be amortized into Utility Operations Revenues over the remaining life of the contracts. |
(g) | Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 2 amounts primarily represent investments in money market funds. |
(h) | Amounts represent corporate, municipal and treasury bonds. |
The following tables set forth a reconciliation of changes in the fair value of net trading derivatives and other investments classified as level 3 in the fair value hierarchy:
Three Months Ended March 31, 2009 | | Net Risk Management Assets (Liabilities) | | | Other Temporary Investments | | | Investments in Debt Securities | |
| | (in millions) | |
Balance as of January 1, 2009 | | $ | 49 | | | $ | - | | | $ | - | |
Realized (Gain) Loss Included in Net Income (or Changes in Net Assets) | | | (12 | ) | | | - | | | | - | |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | | 59 | | | | - | | | | - | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | | - | | | | - | | | | - | |
Purchases, Issuances and Settlements (b) | | | - | | | | - | | | | - | |
Transfers in and/or out of Level 3 (c) | | | (25 | ) | | | - | | | | - | |
Changes in Fair Value Allocated to Regulated Jurisdictions (d) | | | 15 | | | | - | | | | - | |
Balance as of March 31, 2009 | | $ | 86 | | | $ | - | | | $ | - | |
Three Months Ended March 31, 2008 | | Net Risk Management Assets (Liabilities) | | | Other Temporary Investments | | | Investments in Debt Securities | |
| | (in millions) | |
Balance as of January 1, 2008 | | $ | 49 | | | $ | - | | | $ | - | |
Realized (Gain) Loss Included in Net Income (or Changes in Net Assets) | | | (3 | ) | | | - | | | | - | |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | | 5 | | | | - | | | | - | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | | - | | | | - | | | | - | |
Purchases, Issuances and Settlements (b) | | | - | | | | (96 | ) | | | - | |
Transfers in and/or out of Level 3 (c) | | | (5 | ) | | | 118 | | | | 17 | |
Changes in Fair Value Allocated to Regulated Jurisdictions (d) | | | 3 | | | | - | | | | - | |
Balance as of March 31, 2008 | | $ | 49 | | | $ | 22 | | | $ | 17 | |
(a) | Included in revenues on our Condensed Consolidated Statements of Income. |
(b) | Includes principal amount of securities settled during the period. |
(c) | “Transfers in and/or out of Level 3” represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period. |
(d) | “Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected on the Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets. |
We adopted FIN 48 as of January 1, 2007. As a result, we recognized an increase in liabilities for unrecognized tax benefits, as well as related interest and penalties, which was accounted for as a reduction to the January 1, 2007 balance of retained earnings.
We, along with our subsidiaries, file a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current expense. The tax benefit of the Parent is allocated to our subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
We are no longer subject to U.S. federal examination for years before 2000. However, we have filed refund claims with the IRS for years 1997 through 2000 for the CSW pre-merger tax period, which are currently being reviewed. We have completed the exam for the years 2001 through 20032006 and have issues that we are pursuing at the appeals level. The returns for the years 2004 through 2006 are presently under audit by the IRS. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for income taxes have been made for potential liabilities resulting from such matters. In addition, we accrue interest on these uncertain tax positions. We are not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on net income.
We, along with our subsidiaries, file income tax returns in various state, local and foreign jurisdictions. These taxing authorities routinely examine our tax returns and we are currently under examination in several state and local jurisdictions. We believe that we have filed tax returns with positions that may be challenged by these tax authorities. However, management does not believe that the ultimate resolution of these audits will materially impact net income. With few exceptions, we are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2000.
Federal Tax Legislation
In 2005, the Energy Tax Incentives Act of 2005 was signed into law. This act created a limited amount of tax credits for the building of IGCC plants. The credit is 20% of the eligible property in the construction of a new plant or 20% of the total cost of repowering of an existing plant using IGCC technology. In the case of a newly constructed IGCC plant, eligible property is defined as the components necessary for the gasification of coal, including any coal handling and gas separation equipment. We announced plans to construct two new IGCC plants that may be eligible for the allocation of these credits. We filed applications for the West Virginia and Ohio IGCC projects with the DOE and the IRS. Both projects were certified by the DOE and qualified by the IRS. However, neither project was allocated credits during the first round of credit awards. After one of the original credit recipients surrendered their credits in the Fall of 2007, the IRS announced a supplemental credit round for the Spring of 2008. We filed a new application in 2008 for the West Virginia IGCC project and in July 2008 the IRS allocated the project $134 million in credits. In September 2008, we entered into a memorandum of understanding with the IRS concerning the requirements of claiming the credits.
In October 2008, the Emergency Economic Stabilization Act of 2008 (the Act) was signed into law. The Act extended several expiring tax provisions and added new energy incentive provisions. The legislation impacted the availability of research credits, accelerated depreciation of smart meters, production tax credits and energy efficient commercial building deductions. We have evaluated the impact of the law change and the application of the law change will not materially impact our net income, cash flows or financial condition.
State Tax Legislation
In March 2008, the Governor of West Virginia signed legislation providing for, among other things, a reduction in the West Virginia corporate income tax rate from 8.75% to 8.5% beginning in 2009. The corporate income tax rate could also be reduced to 7.75% in 2012 and 7% in 2013 contingent upon the state government achieving certain minimum levels of shortfall reserve funds. We have evaluated the impact of the law change and the application of the law change will not materially impact our net income, cash flows or financial condition.
Common Stock
In April 2009, we issued 69 million shares of common stock at $24.50 per share for net proceeds of $1.64 billion. We used $1.25 billion of the proceeds to repay part of the cash drawn under our credit facilities.
Long-term Debt
| | September 30, | | | December 31, | |
Type of Debt | | 2008 | | | 2007 | |
| | (in millions) | |
Senior Unsecured Notes | | $ | 11,186 | | | $ | 9,905 | |
Pollution Control Bonds | | | 1,817 | | | | 2,190 | |
First Mortgage Bonds | | | - | | | | 19 | |
Notes Payable | | | 244 | | | | 311 | |
Securitization Bonds | | | 2,132 | | | | 2,257 | |
Junior Subordinated Debentures | | | 315 | | | | - | |
Notes Payable To Trust | | | 113 | | | | 113 | |
Spent Nuclear Fuel Obligation (a) | | | 264 | | | | 259 | |
Other Long-term Debt | | | 2 | | | | 2 | |
Unamortized Discount (net) | | | (66 | ) | | | (62 | ) |
Total Long-term Debt Outstanding | | | 16,007 | | | | 14,994 | |
Less Portion Due Within One Year | | | 682 | | | | 792 | |
Long-term Portion | | $ | 15,325 | | | $ | 14,202 | |
| | March 31, | | | December 31, | |
Type of Debt | | 2009 | | | 2008 | |
| | (in millions) | |
Senior Unsecured Notes | | $ | 11,890 | | | $ | 11,069 | |
Pollution Control Bonds | | | 2,080 | | | | 1,946 | |
Notes Payable | | | 224 | | | | 233 | |
Securitization Bonds | | | 2,051 | | | | 2,132 | |
Junior Subordinated Debentures | | | 315 | | | | 315 | |
Spent Nuclear Fuel Obligation (a) | | | 264 | | | | 264 | |
Other Long-term Debt | | | 88 | | | | 88 | |
Unamortized Discount (net) | | | (69 | ) | | | (64 | ) |
Total Long-term Debt Outstanding | | | 16,843 | | | | 15,983 | |
Less Portion Due Within One Year | | | 939 | | | | 447 | |
Long-term Portion | | $ | 15,904 | | | $ | 15,536 | |
(a) | Pursuant to the Nuclear Waste Policy Act of 1982, I&M (a nuclear licensee) has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation of $297$304 million and $285$301 million at September 30, 2008March 31, 2009 and December 31, 2007,2008, respectively, are included in Spent Nuclear Fuel and Decommissioning Trusts on our Condensed Consolidated Balance Sheets. |
Long-term debt and other securities issued, retired and principal payments made during the first ninethree months of 20082009 are shown in the tables below.
Company | | Type of Debt | | Principal Amount | | Interest Rate | | Due Date |
| | | | (in millions) | | (%) | | |
Issuances: | | | | | | | | |
AEP | | Junior Subordinated Debentures | | $ | 315 | | 8.75 | | 2063 |
APCo | | Pollution Control Bonds | | | 40 | | 4.85 | | 2019 |
APCo | | Pollution Control Bonds | | | 30 | | 4.85 | | 2019 |
APCo | | Pollution Control Bonds | | | 75 | | Variable | | 2036 |
APCo | | Pollution Control Bonds | | | 50 | | Variable | | 2036 |
APCo | | Senior Unsecured Notes | | | 500 | | 7.00 | | 2038 |
CSPCo | | Senior Unsecured Notes | | | 350 | | 6.05 | | 2018 |
I&M | | Pollution Control Bonds | | | 25 | | Variable | | 2019 |
I&M | | Pollution Control Bonds | | | 52 | | Variable | | 2021 |
I&M | | Pollution Control Bonds | | | 40 | | 5.25 | | 2025 |
OPCo | | Pollution Control Bonds | | | 50 | | Variable | | 2014 |
OPCo | | Pollution Control Bonds | | | 50 | | Variable | | 2014 |
OPCo | | Pollution Control Bonds | | | 65 | | Variable | | 2036 |
OPCo | | Senior Unsecured Notes | | | 250 | | 5.75 | | 2013 |
SWEPCo | | Pollution Control Bonds | | | 41 | | 4.50 | | 2011 |
SWEPCo | | Senior Unsecured Notes | | | 400 | | 6.45 | | 2019 |
| | | | | | | | | |
Non-Registrant: | | | | | | | | | |
TCC | | Pollution Control Bonds | | | 41 | | 5.625 | | 2017 |
TCC | | Pollution Control Bonds | | | 120 | | 5.125 | | 2030 |
TNC | | Senior Unsecured Notes | | | 30 | | 5.89 | | 2018 |
TNC | | Senior Unsecured Notes | | | 70 | | 6.76 | | 2038 |
Total Issuances | | | | $ | 2,594 | (a) | | | |
Other than the possible dividend restrictions of the AEP Junior Subordinated Debentures, theCompany | | Type of Debt | | Principal Amount | | Interest Rate | | Due Date |
| | | | (in millions) | | (%) | | |
Issuances: | | | | | | | | |
APCo | | Senior Unsecured Notes | | $ | 350 | | 7.95 | | 2020 |
I&M | | Senior Unsecured Notes | | | 475 | | 7.00 | | 2019 |
I&M | | Pollution Control Bonds | | | 50 | | 6.25 | | 2025 |
I&M | | Pollution Control Bonds | | | 50 | | 6.25 | | 2025 |
PSO | | Pollution Control Bonds | | | 34 | | 5.25 | | 2014 |
| | | | | | | | | |
Total Issuances | | | | $ | 959 | (a) | | | |
The above borrowing arrangements do not contain guarantees, collateral or dividend restrictions.
(a) | Amount indicated on statement of cash flows of $2,561$947 million is net of issuance costs and premium or discount. |
The net proceeds from the sale of Junior Subordinated Debentures were used for general corporate purposes including the payment of short-term indebtedness. Company | | Type of Debt | | Principal Amount Paid | | Interest Rate | | Due Date | | Type of Debt | | Principal Amount Paid | | Interest Rate | | Due Date |
| | | | (in millions) | | (%) | | | | | | (in millions) | | (%) | | |
Retirements and Principal Payments: | | | | | | | | | | | | | | | | |
APCo | | Senior Unsecured Notes | | $ | 200 | | 3.60 | | 2008 | |
APCo | | Pollution Control Bonds | | 40 | | Variable | | 2019 | |
APCo | | Pollution Control Bonds | | 30 | | Variable | | 2019 | |
APCo | | Pollution Control Bonds | | 18 | | Variable | | 2021 | |
APCo | | Pollution Control Bonds | | 50 | | Variable | | 2036 | |
APCo | | Pollution Control Bonds | | 75 | | Variable | | 2037 | |
CSPCo | | Senior Unsecured Notes | | 60 | | 6.55 | | 2008 | |
CSPCo | | Senior Unsecured Notes | | 52 | | 6.51 | | 2008 | |
CSPCo | | Pollution Control Bonds | | 48 | | Variable | | 2038 | |
CSPCo | | Pollution Control Bonds | | 44 | | Variable | | 2038 | |
I&M | | Pollution Control Bonds | | 45 | | Variable | | 2009 | |
I&M | | Pollution Control Bonds | | 25 | | Variable | | 2019 | |
I&M | | Pollution Control Bonds | | 52 | | Variable | | 2021 | |
I&M | | Pollution Control Bonds | | 50 | | Variable | | 2025 | |
I&M | | Pollution Control Bonds | | 50 | | Variable | | 2025 | |
I&M | | Pollution Control Bonds | | 40 | | Variable | | 2025 | |
OPCo | | Notes Payable | | 1 | | 6.81 | | 2008 | | Notes Payable | | $ | 1 | | 6.27 | | 2009 |
OPCo | | Notes Payable | | 12 | | 6.27 | | 2009 | | Notes Payable | | 4 | | 7.21 | | 2009 |
OPCo | | Pollution Control Bonds | | 50 | | Variable | | 2014 | |
OPCo | | Pollution Control Bonds | | 50 | | Variable | | 2016 | |
OPCo | | Pollution Control Bonds | | 50 | | Variable | | 2022 | |
OPCo | | Pollution Control Bonds | | 35 | | Variable | | 2022 | |
OPCo | | Pollution Control Bonds | | 65 | | Variable | | 2036 | |
PSO | | Pollution Control Bonds | | 34 | | Variable | | 2014 | |
SWEPCo | | Pollution Control Bonds | | 41 | | Variable | | 2011 | |
SWEPCo | | Notes Payable | | 2 | | Variable | | 2008 | |
SWEPCo | | Notes Payable | | 3 | | 4.47 | | 2011 | | Notes Payable | | 1 | | 4.47 | | 2011 |
| | | | | | | | | | | | | | | | |
Non-Registrant: | | | | | | | | | | | | | | | | |
AEP Subsidiaries | | Notes Payable | | 4 | | 5.88 | | 2011 | | Notes Payable | | 3 | | Variable | | 2017 |
AEP Subsidiaries | | Notes Payable | | 10 | | Variable | | 2017 | |
AEGCo | | Senior Unsecured Notes | | 7 | | 6.33 | | 2037 | | Senior Unsecured Notes | | 4 | | 6.33 | | 2037 |
AEPSC | | Notes Payable | | 34 | | 9.60 | | 2008 | |
TCC | | First Mortgage Bonds | | 19 | | 7.125 | | 2008 | |
TCC | | Securitization Bonds | | 29 | | 5.01 | | 2008 | |
TCC | | Securitization Bonds | | 21 | | 5.56 | | 2010 | |
TCC | | Securitization Bonds | | 75 | | 4.98 | | 2010 | |
TCC | | Pollution Control Bonds | | 41 | | Variable | | 2015 | |
TCC | | Pollution Control Bonds | | 60 | | Variable | | 2028 | | Securitization Bonds | | 31 | | 5.56 | | 2010 |
TCC | | Pollution Control Bonds | | | 60 | | Variable | | 2028 | | Securitization Bonds | | | 50 | | 4.98 | | 2010 |
Total Retirements and Principal Payments | Total Retirements and Principal Payments | | | $ | 1,582 | | | | | | | | $ | 94 | | | | |
In OctoberDuring 2008, SWEPCo retired $113we chose to begin eliminating our auction-rate debt position due to market conditions. As of March 31, 2009, $272 million of 5.25% Notes Payable due in 2043.
As of September 30, 2008, we had $272 million outstanding ofour auction-rate tax-exempt long-term debt, sold at auctionwith rates (rates rangeranging between 4.353%1.676% and 13%) that, remained outstanding with rates 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 bond insurers previously AAA-rated, namely Ambac Assurance Corporation and Financial Guaranty Insurance Co. Due to the exposure that these bond insurers had in connection with developments in the subprime credit market, the credit ratings of these 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, including many of the auctions of our tax-exempt long-term debt. Consequently, we chose to exit the auction-rate debt market. 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. Through September 30, 2008, we reduced our outstanding auction rate securities by $1.2 billion. We plan to continue the conversion and refunding process for the remaining $272 million to other permitted modes, including term-put structures, variable-rate and fixed-rate structures, as opportunities arise.
As of September 30, 2008, $367Approximately $218 million of the $272 million of outstanding auction-rate debt relates to a lease structure with JMG that we are unable to refinance without their consent. The rates for this debt are at contractual maximum rate of 13%. The initial term for the JMG lease structure matures on March 31, 2010. We are evaluating whether to terminate this facility prior auction rate debt wasto maturity. Termination of this facility requires approval from the PUCO.
During the first quarter of 2009, we issued in a weekly variable rate mode supported$134 million of Pollution Control Bonds which were previously held by letters of credit at variable rates ranging from 6.5% to 8.25% and $495 million was issued at fixed rates ranging from 4.5% to 5.625%.trustees on our behalf. As of September 30, 2008,March 31, 2009, trustees held, on our behalf, approximately $330$195 million of our remaining reacquired auction rateauction-rate tax-exempt long-term debt which we plan to reissue to the public as market conditions permit.
Dividend Restrictions
We have the option to defer interest payments on the 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.
Short-term Debt
Our outstanding short-term debt is as follows:
| | September 30, 2008 | | December 31, 2007 | |
| | Outstanding | | Interest | | Outstanding | | Interest | |
| | Amount | | Rate | | Amount | | Rate | |
Type of Debt | | (in thousands) | | | | (in thousands) | | | |
Commercial Paper – AEP | | $ | 701,416 | | 3.25% | (a) | $ | 659,135 | | 5.54% | (a) |
Commercial Paper – JMG (b) | | | - | | - | | | 701 | | 5.35% | (a) |
Line of Credit – Sabine Mining Company (c) | | | 9,520 | | 7.75% | (a) | | 285 | | 5.25% | (a) |
Line of Credit – AEP (e) | | | 590,700 | | 3.4813% | (d) | | - | | - | |
Total | | $ | 1,301,636 | | | | $ | 660,121 | | | |
| | March 31, 2009 | | | December 31, 2008 | |
| | Outstanding Amount | | Interest Rate (a) | | | Outstanding Amount | | Interest Rate (a) | |
Type of Debt | | (in thousands) | | | | | (in thousands) | | | |
Line of Credit – AEP | | $ | 1,969,000 | (b) | 1.22% | (c) | | $ | 1,969,000 | | 2.28% | (c) |
Line of Credit – Sabine Mining Company (d) | | | 6,559 | | 1.82% | | | | 7,172 | | 1.54% | |
Total | | $ | 1,975,559 | | | | | $ | 1,976,172 | | | |
(a) | Weighted average rate. |
(b) | This commercial paper is specifically associatedPaid $1.25 billion with proceeds from the Gavin Scrubber and is backed by a separate credit facility. This commercial paper does not reduce available liquidity under AEP’s credit facilities.equity issuance in April 2009. |
(c) | Rate based on LIBOR. |
(d) | Sabine Mining Company is consolidated under FIN 46R. This line of credit does not reduce available liquidity under AEP’s credit facilities. |
(d) | Rate based on 1-month LIBOR. In October 2008, this rate was converted to 4.55% based on prime. |
(e) | In October 2008, we borrowed an additional $1.4 billion at 4.55% based on prime. |
Credit Facilities
As of September 30, 2008, inMarch 31, 2009, we have credit facilities totaling $3 billion to support of our commercial paper program we had 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, theThe facilities are structured as two $1.5 billion credit facilities were amended so thatof which $750 million may be issued under each credit facility as letters of credit.
In April 2008, we entered intoWe have 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,March 31, 2009, $372 million of letters of credit were issued by subsidiaries under the $650 million 3-year credit agreement to support variable rate demand notes.
Sale of Receivables – AEP Credit
Pollution Control Bonds. In October 2008, we renewed AEP Credit’s sale of receivables agreement. The sale of receivablesApril 2009, the $350 million 364-day credit agreement provides a commitment of $600 million from bank conduits to purchase receivables from AEP Credit. This agreement will expire in October 2009.
expired.
APPALACHIAN POWER COMPANY
AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
ThirdFirst Quarter of 20082009 Compared to ThirdFirst Quarter of 20072008
Reconciliation of ThirdFirst Quarter of 20072008 to ThirdFirst Quarter of 20082009
Net Income Before Extraordinary Loss
(in millions)
Third Quarter of 2007 | | | | | $ | 24 | |
| | | | | | | |
Changes in Gross Margin: | | | | | | | |
Retail Margins | | | (9 | ) | | | | |
Off-system Sales | | | 8 | | | | | |
Other | | | 1 | | | | | |
Total Change in Gross Margin | | | | | | | - | |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | 26 | | | | | |
Depreciation and Amortization | | | (10 | ) | | | | |
Taxes Other Than Income Taxes | | | (1 | ) | | | | |
Carrying Costs Income | | | 3 | | | | | |
Other Income | | | 2 | | | | | |
Interest Expense | | | (2 | ) | | | | |
Total Change in Operating Expenses and Other | | | | | | | 18 | |
| | | | | | | | |
Income Tax Expense | | | | | | | (3 | ) |
| | | | | | | | |
Third Quarter of 2008 | | | | | | $ | 39 | |
First Quarter of 2008 | | | | | $ | 55 | |
| | | | | | | |
Changes in Gross Margin: | | | | | | | |
Retail Margins | | | 87 | | | | | |
Off-system Sales | | | (47 | ) | | | | |
Other | | | 1 | | | | | |
Total Change in Gross Margin | | | | | | | 41 | |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | 12 | | | | | |
Depreciation and Amortization | | | (7 | ) | | | | |
Carrying Costs Income | | | (6 | ) | | | | |
Other Income | | | (1 | ) | | | | |
Interest Expense | | | (6 | ) | | | | |
Total Change in Operating Expenses and Other | | | | | | | (8 | ) |
| | | | | | | | |
Income Tax Expense | | | | | | | (14 | ) |
| | | | | | | | |
First Quarter of 2009 | | | | | | $ | 74 | |
Net Income Before Extraordinary Loss increased $15$19 million to $39$74 million in 2008 primarily due to2009. The key drivers of the increase were a decrease$41 million increase in Operating Expenses and Other of $18 million,Gross Margin, partially offset by ana $14 million increase in Income Tax Expense of $3 million.and an $8 million increase in Operating Expenses and Other.
The major components of the change in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:
· | Retail Margins decreased $9 million primarily due to an increase in sharing of off-system sales margins with customers and higher capacity settlement expenses under the Interconnection Agreement. These unfavorable effects were partially offset by the impact of the Virginia base rate order issued in May 2007 which included a 2007 provision for revenue refund in addition to an increase in the recovery of E&R costs in Virginia. |
· | Margins from Off-system Sales increased $8 million primarily due to increased physical sales margins driven by higher prices, partially offset by lower trading margins. |
Operating Expenses and Other and Income Tax Expense changed between years as follows:
· | Other Operation and Maintenance expenses decreased $26 million primarily due to the following: |
| · | A $26 million decrease resulting from a settlement agreement in the third quarter 2007 related to alleged violations of the NSR provisions of the CAA. The $26 million represents APCo’s allocation of the settlement. |
| · | A $9 million decrease related to the establishment of a regulatory asset in the third quarter 2008 for Virginia’s share of previously expended NSR settlement costs. See “Virginia E&R Cost Recovery Filing” section of Note 3. |
| These decreases were partially offset by: |
| · | A $6 million increase in employee-related expenses. |
| · | A $5 million increase in overhead line maintenance expense primarily due to right-of-way clearing. |
· | Depreciation and Amortization expenses increased $10 million primarily due to a $6 million increase in the amortization of carrying charges and depreciation expense that are being collected through the Virginia E&R surcharges and a $3 million increase in depreciation expense primarily from the installation of environmental upgrades at the Mountaineer Plant. |
· | Carrying Costs Income increased $3 million due to an increase in Virginia E&R deferrals. |
· | Income Tax Expense increased $3 million primarily due to an increase in pretax book income, partially offset by changes in certain book/tax differences accounted for on a flow-through basis. |
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 Before Extraordinary Loss
(in millions)
Nine Months Ended September 30, 2007 | | | | | $ | 98 | |
| | | | | | | |
Changes in Gross Margin: | | | | | | | |
Retail Margins | | | 19 | | | | | |
Off-system Sales | | | 32 | | | | | |
Other | | | 1 | | | | | |
Total Change in Gross Margin | | | | | | | 52 | |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | 12 | | | | | |
Depreciation and Amortization | | | (44 | ) | | | | |
Taxes Other Than Income Taxes | | | (5 | ) | | | | |
Carrying Costs Income | | | 16 | | | | | |
Other Income | | | 7 | | | | | |
Interest Expense | | | (17 | ) | | | | |
Total Change in Operating Expenses and Other | | | | | | | (31 | ) |
| | | | | | | | |
Income Tax Expense | | | | | | | 2 | |
| | | | | | | | |
Nine Months Ended September 30, 2008 | | | | | | $ | 121 | |
Income Before Extraordinary Loss increased $23 million to $121 million in 2008 primarily due to an increase in Gross Margin of $52 million, partially offset by a $31 million increase in Operating Expenses and Other.
The major components of the change in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:
· | Retail Margins increased $19$87 million primarily due to the following: |
| · | A $49 million increase in rate relief primarily due to the impact of the Virginia base rate order issued in May 2007 which included a 2007 provision for revenue refund in addition toOctober 2008, an increase in the recovery of E&R costs in Virginia and an increase in the recovery of construction financing costs in West Virginia. These increases were partially offset by an |
| · | A $39 million increase due to a decrease in sharing of off-system sales margins with customers in Virginia and West Virginia. |
| · | A $7 million increase due to new rates effective January 2009 for a power supply contract with KGPCo. |
| · | A $3 million increase in residential and commercial revenue primarily due to increased usage resulting from a 5% increase in heating degree days. |
| These increases were partially offset by: |
| · | A $14 million decrease due to higher capacity settlement expenses under the Interconnection Agreement.Agreement net of recovery in West Virginia and environmental deferrals in Virginia. |
· | Margins from Off-system Sales increased $32decreased $47 million primarily due to increasedlower physical sales volumes and lower margins driven by higheras a result of lower market prices, partially offset by lowerhigher trading margins. |
Operating Expenses and Other and Income Tax Expense changed between years as follows:
· | Other Operation and Maintenance expenses decreased $12 million primarily due to the following: |
| · | A $26 million decrease resulting from a settlement agreement in the third quarter 2007 related to alleged violations of the NSR provisions of the CAA. The $26 million represents APCo’s allocation of the settlement. |
| · | A $9 million decrease related to the establishment of a regulatory asset in the third quarter 2008 for Virginia’s share of previously expended NSR settlement costs. See “Virginia E&R Cost Recovery Filing” section of Note 3. |
| These decreases were partially offset by: |
| · | A $7 million increase inlower employee-related expenses. |
| · | A $10 million increase in overhead line maintenance expense due to right-of-way clearingexpenses and storm damage.generation plant maintenance. |
· | Depreciation and Amortization expenses increased $44$7 million primarily due to $22 million in favorable adjustments made ina greater depreciation base resulting from asset improvements and the second quarter 2007 for APCo’s Virginia base rate order and a $15 million increase in amortization of carrying charges and depreciation expenseexpenses that are being collected through the Virginia E&R surcharges. |
· | Taxes Other Than Income Taxes increased $5 million primarily due to favorable franchise tax return adjustments recorded in 2007. |
· | Carrying Costs Income increased $16decreased $6 million due to an increasethe completion of reliability deferrals in Virginia E&R deferrals. |
· | Other Income increased $7 million primarily due to higher interest income related to a tax refund in December 2008 and other tax adjustments.the decrease of environmental deferrals in Virginia in 2009. |
· | Interest Expense increased $17$6 million primarily due to a $26 millionan increase in interest expense from long-term debt issuances, partially offset by a $7 million decrease in interest expense primarily related to interest on the Virginia provision for refund recorded in the second quarter of 2007.issuances. |
· | Income Tax Expense decreased $2increased $14 million primarily due to a decrease in state income taxes and changes in certain book/tax differences accounted for on a flow-through basis, partially offset by an increase in pretax book income.income, partially offset by state income tax adjustments recorded in 2008. |
Financial Condition
Credit Ratings
S&P currently has APCo on stable outlook, while Fitch placed APCo on negative outlook in the second quarterAPCo’s credit ratings as of 2008 and Moody’s placed APCo on negative outlook in the first quarter of 2008. Current ratings areMarch 31, 2009 were as follows:
| Moody’s | | S&P | | Fitch |
| | | | | |
Senior Unsecured Debt | Baa2 | | BBB | | BBB+ |
IfS&P has APCo receives an upgradeon stable outlook, while Fitch has APCo on negative outlook. In February 2009, Moody’s changed its rating outlook for APCo from any of the rating agencies listed above, its borrowing costs could decrease.negative to stable due to recent rate recoveries in Virginia and West Virginia. If APCo receives a downgrade from any of the rating agencies, listed above, itits borrowing costs could increase and access to borrowed funds could be negatively affected.
Cash Flow
Cash flows for the ninethree months ended September 30,March 31, 2009 and 2008 and 2007 were as follows:
| | 2008 | | | 2007 | |
| | (in thousands) | |
Cash and Cash Equivalents at Beginning of Period | | $ | 2,195 | | | $ | 2,318 | |
Cash Flows from (Used for): | | | | | | | | |
Operating Activities | | | 208,445 | | | | 221,534 | |
Investing Activities | | | (472,029 | ) | | | (570,019 | ) |
Financing Activities | | | 263,376 | | | | 347,436 | |
Net Decrease in Cash and Cash Equivalents | | | (208 | ) | | | (1,049 | ) |
Cash and Cash Equivalents at End of Period | | $ | 1,987 | | | $ | 1,269 | |
| | 2009 | | | 2008 | |
| | (in thousands) | |
Cash and Cash Equivalents at Beginning of Period | | $ | 1,996 | | | $ | 2,195 | |
Cash Flows from (Used for): | | | | | | | | |
Operating Activities | | | (29,207 | ) | | | 118,832 | |
Investing Activities | | | (220,590 | ) | | | (409,179 | ) |
Financing Activities | | | 250,355 | | | | 290,804 | |
Net Increase in Cash and Cash Equivalents | | | 558 | | | | 457 | |
Cash and Cash Equivalents at End of Period | | $ | 2,554 | | | $ | 2,652 | |
Operating Activities
Net Cash Flows fromUsed for Operating Activities were $208$29 million in 2008.2009. APCo produced incomeNet Income of $121$74 million during the period and had noncash expense items of $187$70 million for Depreciation and Amortization $111and $80 million for Deferred Income Taxes and $39 million for Carrying Costs Income.Taxes. The 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 working capital relates to a $114number of items. The $116 million cash outflow from Accounts Payable was primarily due to APCo’s provision for revenue refund of $77 million which was paid in the first quarter 2009 to the AEP West companies as part of the FERC’s recent order on the SIA. The $71 million change in Fuel Over/Under-Recovery, Net as a result ofresulted in a net under recoveryunder-recovery of fuel cost in both Virginia and West Virginia due to higher fuel costs.Virginia.
Net Cash Flows from Operating Activities were $222$119 million in 2007.2008. APCo produced incomeNet Income of $19$55 million during the period and hada noncash expense itemsitem of $142$63 million for Depreciation and Amortization, $79 million for Extraordinary Loss for the Reapplication of Regulatory Accounting for Generation and $23 million for Carrying Cost Income.Amortization. The other changes in assets and liabilities represent items that had a priorcurrent 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 working capital had no significant itemsrelates to a number of items. The $32 million cash inflow from Accounts Receivable, Net was primarily due to a settlement of allowance sales to affiliated companies. The $20 million cash inflow from Fuel, Materials and Supplies was primarily due to a reduction in 2007.fuel inventory to reflect planned outages. The $27 million change in Fuel Over/Under-Recovery, Net resulted in a net under-recovery of fuel cost in both Virginia and West Virginia.
Investing Activities
Net Cash Flows Used for Investing Activities during 2009 and 2008 and 2007 were $472$221 million and $570$409 million, respectively. Construction Expenditures were $488$221 million and $538$159 million in 20082009 and 2007,2008, respectively, primarily related to transmission and distribution service reliability projects, as well as environmental upgrades for both periods. Environmental upgrades includesinclude the installation of theselective catalytic reduction equipment on APCo’s plants and flue gas desulfurization equipmentprojects at the Amos and Mountaineer Plants. In February 2007, environmental upgrades were completed forAPCo’s investments in the Mountaineer Plant. For the remainderUtility Money Pool increased by $262 million in 2008. APCo forecasts approximately $368 million of 2008, APCo expects construction expenditures to be approximately $250 million.for all of 2009, excluding AFUDC.
Financing Activities
Net Cash Flows from Financing Activities were $263$250 million in 2008. APCo received capital contributions from the Parent of $175 million.2009. APCo issued $500$350 million of Senior Unsecured Notes in March 2008, $125 million of Pollution Control Bonds in June 2008 and $70 million of Pollution Control Bonds in September 2008. These increases were partially offset by the retirement of $213 million of Pollution Control Bonds and $200 million of Senior Unsecured Notes in the second quarter of 2008. In addition,2009. APCo had a net decrease of $182$74 million in borrowings from the Utility Money Pool.
Net Cash Flows from Financing Activities were $291 million in 2007 were $347 million primarily due to2008. APCo received capital contributions from the issuanceParent of $75 million of Pollution Control Bonds in May 2007 and the issuance ofmillion. APCo issued $500 million of Senior Unsecured Notes in August 2007,March 2008. APCo had a net decrease of retirement of $125$275 million of Senior Unsecured Notes in June 2007. APCo also reduced its short-term borrowings from the Utility Money Pool by $35 million.Pool.
Financing Activity
Long-term debt issuances retirements and principal payments made during the first ninethree months of 20082009 were:
Issuances
| | Principal | | Interest | | Due |
Type of Debt | | Amount | | Rate | | Date |
| | (in thousands) | | (%) | | |
Pollution Control Bonds | | $ | 40,000 | | 4.85 | | 2019 |
Pollution Control Bonds | | | 30,000 | | 4.85 | | 2019 |
Pollution Control Bonds | | | 75,000 | | Variable | | 2036 |
Pollution Control Bonds | | | 50,275 | | Variable | | 2036 |
Senior Unsecured Notes | | | 500,000 | | 7.00 | | 2038 |
| | Principal Amount | | Interest | | Due |
Type of Debt | | | Rate | | Date |
| | (in thousands) | | (%) | | |
Senior Unsecured Debt | | $ | 350,000 | | 7.95 | | 2020 |
Retirements and Principal Payments
| | Principal | | Interest | | Due |
Type of Debt | | Amount Paid | | Rate | | Date |
| | (in thousands) | | (%) | | |
Pollution Control Bonds | | $ | 40,000 | | Variable | | 2019 |
Pollution Control Bonds | | | 30,000 | | Variable | | 2019 |
Pollution Control Bonds | | | 17,500 | | Variable | | 2021 |
Pollution Control Bonds | | | 50,275 | | Variable | | 2036 |
Pollution Control Bonds | | | 75,000 | | Variable | | 2037 |
Senior Unsecured Notes | | | 200,000 | | 3.60 | | 2008 |
Other | | | 11 | | 13.718 | | 2026 |
| | Principal Amount Paid | | Interest | | Due |
Type of Debt | | | Rate | | Date |
| | (in thousands) | | (%) | | |
Land Note | | $ | 4 | | 13.718 | | 2026 |
Liquidity
In recent months, theThe financial markets have become increasingly unstable and constrainedremain volatile at both a global and domestic level. This systemic marketplace distress is impactingcould impact APCo’s access to capital, liquidity and cost of capital. The uncertainties in the creditcapital markets could have significant implications on APCo since it relies on continuing access to capital to fund operations and capital expenditures. Management cannot predict the length of time the credit situation will continue or its impact on APCo’s operations and ability to issue debt at reasonable interest rates.
APCo participates in the Utility Money Pool, which provides access to AEP’s liquidity. APCo has $150 million of Senior Unsecured Notes that will mature in May 2009. To the extent refinancing is unavailable dueAPCo issued $350 million of Senior Unsecured Notes in March 2009 that will be used to the challenging credit markets,pay down its maturity. APCo will rely upon cash flows from operations and access to the Utility Money Pool to fund its maturity, continuingcurrent operations and capital expenditures.
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of liquidity.
Summary Obligation Information
A summary of contractual obligations is included in the 20072008 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” and “Financing Activity” above and letters of credit. In April 2008, the Registrant Subsidiaries and certain other companies in the AEP System 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. As of September 30, 2008, $127 million of letters of credit were issued by APCo under the 3-year credit agreement to support variable rate demand notes.above.
Significant Factors
Litigation and Regulatory Activity
In the ordinary course of business, APCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual outcome of these proceedings 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 which have a probable likelihood of loss and the loss amount can be estimated. For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 20072008 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries”. section. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of relevant factors.
Critical Accounting Estimates
See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 20072008 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.
Adoption of New Accounting Pronouncements
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Market Risks
Risk management assets and liabilities are managed by AEPSC as agent. The related risk management policies and procedures are instituted and administered by AEPSC. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on APCo.
MTM Risk Management Contract Net Assets
The following two tables summarize the various mark-to-market (MTM) positions included in APCo’s Condensed Consolidated Balance Sheet as of September 30, 2008March 31, 2009 and the reasons for changes in total MTM value as compared to December 31, 2007.2008.
Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of September 30, 2008March 31, 2009
(in thousands)
| | | | | Cash Flow | | | | | | | | | | |
| | MTM Risk | | | & | | | DETM | | | | | | | |
| | Management | | | Fair Value | | | Assignment | | | Collateral | | | | |
| | Contracts | | | Hedges | | | (a) | | | Deposits | | | Total | |
Current Assets | | $ | 81,386 | | | $ | 4,104 | | | $ | - | | | $ | (3,532 | ) | | $ | 81,958 | |
Noncurrent Assets | | | 58,881 | | | | 1,036 | | | | - | | | | (4,718 | ) | | | 55,199 | |
Total MTM Derivative Contract Assets | | | 140,267 | | | | 5,140 | | | | - | | | | (8,250 | ) | | | 137,157 | |
| | | | | | | | | | | | | | | | | | | | |
Current Liabilities | | | (69,529 | ) | | | (2,996 | ) | | | (3,127 | ) | | | 547 | | | | (75,105 | ) |
Noncurrent Liabilities | | | (29,631 | ) | | | - | | | | (3,194 | ) | | | 50 | | | | (32,775 | ) |
Total MTM Derivative Contract Liabilities | | | (99,160 | ) | | | (2,996 | ) | | | (6,321 | ) | | | 597 | | | | (107,880 | ) |
| | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 41,107 | | | $ | 2,144 | | | $ | (6,321 | ) | | $ | (7,653 | ) | | $ | 29,277 | |
| | MTM Risk | | | Cash Flow | | | DETM | | | | | | | |
| | Management | | | Hedge | | | Assignment | | | Collateral | | | | |
| | Contracts | | | Contracts | | | (a) | | | Deposits | | | Total | |
Current Assets | | $ | 80,340 | | | $ | 6,570 | | | $ | - | | | $ | (11,715 | ) | | $ | 75,195 | |
Noncurrent Assets | | | 77,857 | | | | 237 | | | | - | | | | (13,323 | ) | | | 64,771 | |
Total MTM Derivative Contract Assets | | | 158,197 | | | | 6,807 | | | | - | | | | (25,038 | ) | | | 139,966 | |
| | | | | | | | | | | | | | | | | | | | |
Current Liabilities | | | (47,628 | ) | | | (518 | ) | | | (2,697 | ) | | | 11,751 | | | | (39,092 | ) |
Noncurrent Liabilities | | | (52,445 | ) | | | (41 | ) | | | (1,830 | ) | | | 24,261 | | | | (30,055 | ) |
Total MTM Derivative Contract Liabilities | | | (100,073 | ) | | | (559 | ) | | | (4,527 | ) | | | 36,012 | | | | (69,147 | ) |
| | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 58,124 | | | $ | 6,248 | | | $ | (4,527 | ) | | $ | 10,974 | | | $ | 70,819 | |
(a) | See “Natural Gas Contracts with DETM” section of Note 1615 of the 20072008 Annual Report. |
MTM Risk Management Contract Net Assets
NineThree Months Ended September 30, 2008March 31, 2009
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2007 | | $ | 45,870 | |
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | | | (13,569 | ) |
Fair Value of New Contracts at Inception When Entered During the Period (a) | | | - | |
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period | | | - | |
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b) | | | 564 | |
Changes in Fair Value Due to Market Fluctuations During the Period (c) | | | (165 | ) |
Changes in Fair Value Allocated to Regulated Jurisdictions (d) | | | 8,407 | |
Total MTM Risk Management Contract Net Assets | | | 41,107 | |
Net Cash Flow & Fair Value Hedge Contracts | | | 2,144 | |
DETM Assignment (e) | | | (6,321 | ) |
Collateral Deposits | | | (7,653 | ) |
Ending Net Risk Management Assets at September 30, 2008 | | $ | 29,277 | |
Total MTM Risk Management Contract Net Assets at December 31, 2008 | | $ | 56,936 | |
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | | | (9,387 | ) |
Fair Value of New Contracts at Inception When Entered During the Period (a) | | | - | |
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period | | | (113 | ) |
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts | | | - | |
Changes in Fair Value Due to Market Fluctuations During the Period (b) | | | (339 | ) |
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | | | 11,027 | |
Total MTM Risk Management Contract Net Assets | | | 58,124 | |
Cash Flow Hedge Contracts | | | 6,248 | |
DETM Assignment (d) | | | (4,527 | ) |
Collateral Deposits | | | 10,974 | |
Ending Net Risk Management Assets at March 31, 2009 | | $ | 70,819 | |
(a) | Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged. |
(b) | Represents the impact of applying AEP’s credit risk when measuring the fair value of derivative liabilities according to SFAS 157. |
(c) | Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc. |
(d)(c) | “Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities.liabilities/assets. |
(e)(d) | See “Natural Gas Contracts with DETM” section of Note 1615 of the 20072008 Annual Report. |
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The following table presents the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash:
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2008March 31, 2009
(in thousands)
| | Remainder | | | | | | | | | | | | | | | After | | | | |
| | 2008 | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | 2012 | | | Total | |
Level 1 (a) | | $ | (998 | ) | | $ | (2,295 | ) | | $ | (21 | ) | | $ | - | | | $ | - | | | $ | - | | | $ | (3,314 | ) |
Level 2 (b) | | | 1,480 | | | | 18,258 | | | | 12,918 | | | | 1,662 | | | | 485 | | | | - | | | | 34,803 | |
Level 3 (c) | | | (3,850 | ) | | | 666 | | | | (1,881 | ) | | | 272 | | | | 152 | | | | - | | | | (4,641 | ) |
Total | | | (3,368 | ) | | | 16,629 | | | | 11,016 | | | | 1,934 | | | | 637 | | | | - | | | | 26,848 | |
Dedesignated Risk Management Contracts (d) | | | 1,403 | | | | 4,720 | | | | 4,681 | | | | 1,823 | | | | 1,632 | | | | - | | | | 14,259 | |
Total MTM Risk Management Contract Net Assets (Liabilities) | | $ | (1,965 | ) | | $ | 21,349 | | | $ | 15,697 | | | $ | 3,757 | | | $ | 2,269 | | | $ | - | | | $ | 41,107 | |
| | Remainder | | | | | | | | | | | | | | | After | | | | |
| | 2009 | | | 2010 | | | 2011 | | | 2012 | | | 2013 | | | 2013 | | | Total | |
Level 1 (a) | | $ | (1,815 | ) | | $ | (47 | ) | | $ | 1 | | | $ | - | | | $ | - | | | $ | - | | | $ | (1,861 | ) |
Level 2 (b) | | | 19,116 | | | | 10,941 | | | | 6,365 | | | | (511 | ) | | | 38 | | | | - | | | | 35,949 | |
Level 3 (c) | | | 5,508 | | | | 2,773 | | | | 1,679 | | | | 1,668 | | | | 219 | | | | - | | | | 11,847 | |
Total | | | 22,809 | | | | 13,667 | | | | 8,045 | | | | 1,157 | | | | 257 | | | | - | | | | 45,935 | |
Dedesignated Risk Management Contracts (d) | | | 3,739 | | | | 4,862 | | | | 1,894 | | | | 1,694 | | | | - | | | | - | | | | 12,189 | |
Total MTM Risk Management Contract Net Assets | | $ | 26,548 | | | $ | 18,529 | | | $ | 9,939 | | | $ | 2,851 | | | $ | 257 | | | $ | - | | | $ | 58,124 | |
(a) | Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis. |
(b) | Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1 and OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market. |
(c) | Level 3 inputs are unobservable inputs for the asset or liability. Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions. |
(d) | Dedesignated Risk Management Contracts are contracts that were originally MTM but were subsequently elected as normal under SFAS 133. At the time of the normal election, the MTM value was frozen and no longer fair valued. This will be amortized into Revenues over the remaining life of the contract.contracts. |
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed Consolidated Balance Sheet
APCo is exposed to market fluctuations in energy commodity prices impacting power operations. Management monitors these risks on future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows. Management does not hedge all commodity price risk.
Management uses interest rate derivative transactions to manage interest rate risk related to anticipated borrowings of fixed-rate debt. Management does not hedge all interest rate risk.
Management uses foreign currency derivatives to lock in prices on certain forecasted transactions denominated in foreign currencies where deemed necessary, and designates qualifying instruments as cash flow hedges. Management does not hedge all foreign currency exposure.
The following table provides the detail on designated, effective cash flow hedges included in AOCI on APCo’s Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 2007 to September 30, 2008. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2008
(in thousands)
| | | | | Interest | | | Foreign | | | |
| | Power | | | Rate | | | Currency | | | Total |
Beginning Balance in AOCI December 31, 2007 | | $ | 783 | | | $ | (6,602) | | | $ | (125) | | | $ | (5,944) |
Changes in Fair Value | | | 670 | | | | (3,114) | | | | 68 | | | | (2,376) |
Reclassifications from AOCI for Cash Flow Hedges Settled | | | (118) | | | | 1,231 | | | | 5 | | | | 1,118 |
Ending Balance in AOCI September 30, 2008 | | $ | 1,335 | | | $ | (8,485) | | | $ | (52) | | | $ | (7,202) |
The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $1 million loss.
Credit Risk
Counterparty credit quality and exposure is generally consistent with that of AEP.
See Note 7 for further information regarding MTM risk management contracts, cash flow hedging, accumulated other comprehensive income, credit risk and collateral triggering events.
VaR Associated with Risk Management Contracts
Management uses a risk measurement model, which calculates Value at Risk (VaR) to measure commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at September 30, 2008,March 31, 2009, a near term typical change in commodity prices is not expected to have a material effect on APCo’s net income, cash flows or financial condition.
The following table shows the end, high, average, and low market risk as measured by VaR for the periods indicated:
Nine Months Ended September 30, 2008 | | Twelve Months Ended December 31, 2007 | |
Three Months Ended | | Three Months Ended | | Twelve Months Ended |
March 31, 2009 | | March 31, 2009 | | December 31, 2008 |
(in thousands) | (in thousands) | | (in thousands) | (in thousands) | | (in thousands) |
End | | High | | Average | | Low | | End | | High | | Average | | Low | | High | | Average | | Low | | End | | High | | Average | | Low |
$725 | | $1,096 | | $416 | | $161 | | $455 | | $2,328 | | $569 | | $117 | |
$297 | | | $546 | | $306 | | $151 | | $176 | | $1,096 | | $396 | | $161 |
Management back-tests its VaR results against performance due to actual price moves. Based on the assumed 95% confidence interval, the performance due to actual price moves would be expected to exceed the VaR at least once every 20 trading days. Management’s backtesting results show that its actual performance exceeded VaR far fewer than once every 20 trading days. As a result, management believes APCo’s VaR calculation is conservative.
As APCo’s VaR calculation captures recent price moves, management also performs regular stress testing of the portfolio to understand itsAPCo’s exposure to extreme price moves. Management employs a historically-basedhistorical-based method whereby the current portfolio is subjected to actual, observed price moves from the last three years in order to ascertain which historical price moves translatetranslated into the largest potential mark-to-marketMTM loss. Management then researches the underlying positions, price moves and market events that created the most significant exposure.
Interest Rate Risk
Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which APCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months. The estimated EaR on APCo’s debt portfolio was $4.3$7.8 million.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30,March 31, 2009 and 2008 and 2007
(in thousands)
(Unaudited)
| | Three Months Ended | | | Nine Months Ended | |
| | 2008 | | | 2007 | | | 2008 | | | 2007 | |
REVENUES | | | | | | | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 719,295 | | | $ | 639,830 | | | $ | 1,926,841 | | | $ | 1,740,565 | |
Sales to AEP Affiliates | | | 74,632 | | | | 64,099 | | | | 262,230 | | | | 181,015 | |
Other | | | 4,906 | | | | 2,647 | | | | 12,186 | | | | 8,134 | |
TOTAL | | | 798,833 | | | | 706,576 | | | | 2,201,257 | | | | 1,929,714 | |
| | | | | | | | | | | | | | | | |
EXPENSES | | | | | | | | | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 220,955 | | | | 200,702 | | | | 554,022 | | | | 535,906 | |
Purchased Electricity for Resale | | | 71,075 | | | | 47,430 | | | | 167,205 | | | | 117,708 | |
Purchased Electricity from AEP Affiliates | | | 219,595 | | | | 171,288 | | | | 595,433 | | | | 443,519 | |
Other Operation | | | 66,316 | | | | 94,190 | | | | 210,262 | | | | 236,944 | |
Maintenance | | | 51,292 | | | | 49,708 | | | | 161,371 | | | | 146,875 | |
Depreciation and Amortization | | | 62,364 | | | | 51,864 | | | | 186,528 | | | | 142,100 | |
Taxes Other Than Income Taxes | | | 24,319 | | | | 23,561 | | | | 72,414 | | | | 67,811 | |
TOTAL | | | 715,916 | | | | 638,743 | | | | 1,947,235 | | | | 1,690,863 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 82,917 | | | | 67,833 | | | | 254,022 | | | | 238,851 | |
| | | | | | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | | | | | |
Interest Income | | | 1,945 | | | | 510 | | | | 7,541 | | | | 1,539 | |
Carrying Costs Income | | | 11,924 | | | | 8,701 | | | | 38,921 | | | | 22,817 | |
Allowance for Equity Funds Used During Construction | | | 2,130 | | | | 1,084 | | | | 6,278 | | | | 5,442 | |
Interest Expense | | | (47,385 | ) | | | (44,980 | ) | | | (138,644 | ) | | | (121,758 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 51,531 | | | | 33,148 | | | | 168,118 | | | | 146,891 | |
| | | | | | | | | | | | | | | | |
Income Tax Expense | | | 12,516 | | | | 9,090 | | | | 47,508 | | | | 49,325 | |
| | | | | | | | | | | | | | | | |
INCOME BEFORE EXTRAORDINARY LOSS | | | 39,015 | | | | 24,058 | | | | 120,610 | | | | 97,566 | |
| | | | | | | | | | | | | | | | |
Extraordinary Loss – Reapplication of Regulatory Accounting for Generation, Net of Tax | | | - | | | | - | | | | - | | | | (78,763 | ) |
| | | | | | | | | | | | | | | | |
NET INCOME | | | 39,015 | | | | 24,058 | | | | 120,610 | | | | 18,803 | |
| | | | | | | | | | | | | | | | |
Preferred Stock Dividend Requirements Including Capital Stock Expense | | | 238 | | | | 238 | | | | 714 | | | | 714 | |
| | | | | | | | | | | | | | | | |
EARNINGS APPLICABLE TO COMMON STOCK | | $ | 38,777 | | | $ | 23,820 | | | $ | 119,896 | | | $ | 18,089 | |
| | 2009 | | | 2008 | |
REVENUES | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 727,959 | | | $ | 641,457 | |
Sales to AEP Affiliates | | | 56,231 | | | | 90,090 | |
Other | | | 1,839 | | | | 3,480 | |
TOTAL | | | 786,029 | | | | 735,027 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 143,681 | | | | 173,830 | |
Purchased Electricity for Resale | | | 75,816 | | | | 43,199 | |
Purchased Electricity from AEP Affiliates | | | 197,124 | | | | 189,595 | |
Other Operation | | | 65,502 | | | | 75,531 | |
Maintenance | | | 55,910 | | | | 57,844 | |
Depreciation and Amortization | | | 69,995 | | | | 62,572 | |
Taxes Other Than Income Taxes | | | 24,103 | | | | 23,991 | |
TOTAL | | | 632,131 | | | | 626,562 | |
| | | | | | | | |
OPERATING INCOME | | | 153,898 | | | | 108,465 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest Income | | | 382 | | | | 2,769 | |
Carrying Costs Income | | | 4,083 | | | | 9,586 | |
Allowance for Equity Funds Used During Construction | | | 2,653 | | | | 1,496 | |
Interest Expense | | | (49,705 | ) | | | (44,140 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 111,311 | | | | 78,176 | |
| | | | | | | | |
Income Tax Expense | | | 36,904 | | | | 22,863 | |
| | | | | | | | |
NET INCOME | | | 74,407 | | | | 55,313 | |
| | | | | | | | |
Preferred Stock Dividend Requirements Including Capital Stock Expense | | | 225 | | | | 238 | |
| | | | | | | | |
EARNINGS ATTRIBUTABLE TO COMMON STOCK | | $ | 74,182 | | | $ | 55,075 | |
The common stock of APCo is wholly-owned by AEP. |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the NineThree Months Ended September 30,March 31, 2009 and 2008 and 2007
(in thousands)
(Unaudited)
| | Common Stock | | | Paid-in Capital | | | Retained Earnings | | | Accumulated Other Comprehensive Income (Loss) | | | Total | |
DECEMBER 31, 2006 | | $ | 260,458 | | | $ | 1,024,994 | | | $ | 805,513 | | | $ | (54,791 | ) | | $ | 2,036,174 | |
| | | | | | | | | | | | | | | | | | | | |
FIN 48 Adoption, Net of Tax | | | | | | | | | | | (2,685 | ) | | | | | | | (2,685 | ) |
Common Stock Dividends | | | | | | | | | | | (25,000 | ) | | | | | | | (25,000 | ) |
Preferred Stock Dividends | | | | | | | | | | | (600 | ) | | | | | | | (600 | ) |
Capital Stock Expense | | | | | | | 117 | | | | (114 | ) | | | | | | | 3 | |
TOTAL | | | | | | | | | | | | | | | | | | | 2,007,892 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $539 | | | | | | | | | | | | | | | (1,000 | ) | | | (1,000 | ) |
SFAS 158 Costs Established as a Regulatory Asset Related to the Reapplication of SFAS 71, Net of Tax of $6,055 | | | | | | | | | | | | | | | 11,245 | | | | 11,245 | |
NET INCOME | | | | | | | | | | | 18,803 | | | | | | | | 18,803 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 29,048 | |
| | | | | | | | | | | | | | | | | | | | |
SEPTEMBER 30, 2007 | | $ | 260,458 | | | $ | 1,025,111 | | | $ | 795,917 | | | $ | (44,546 | ) | | $ | 2,036,940 | |
| | | | | | | | | | | | | | | | | | | | |
DECEMBER 31, 2007 | | $ | 260,458 | | | $ | 1,025,149 | | | $ | 831,612 | | | $ | (35,187 | ) | | $ | 2,082,032 | |
| | | | | | | | | | | | | | | | | | | | |
EITF 06-10 Adoption, Net of Tax of $1,175 | | | | | | | | | | | (2,181 | ) | | | | | | | (2,181 | ) |
SFAS 157 Adoption, Net of Tax of $154 | | | | | | | | | | | (286 | ) | | | | | | | (286 | ) |
Capital Contribution from Parent | | | | | | | 175,000 | | | | | | | | | | | | 175,000 | |
Preferred Stock Dividends | | | | | | | | | | | (599 | ) | | | | | | | (599 | ) |
Capital Stock Expense | | | | | | | 115 | | | | (115 | ) | | | | | | | - | |
TOTAL | | | | | | | | | | | | | | | | | | | 2,253,966 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $677 | | | | | | | | | | | | | | | (1,258 | ) | | | (1,258 | ) |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,346 | | | | | | | | | | | | | | | 2,499 | | | | 2,499 | |
NET INCOME | | | | | | | | | | | 120,610 | | | | | | | | 120,610 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 121,851 | |
| | | | | | | | | | | | | | | | | | | | |
SEPTEMBER 30, 2008 | | $ | 260,458 | | | $ | 1,200,264 | | | $ | 949,041 | | | $ | (33,946 | ) | | $ | 2,375,817 | |
| | Common Stock | | | Paid-in Capital | | | Retained Earnings | | | Accumulated Other Comprehensive Income (Loss) | | | Total | |
| | | | | | | | | | | | | | | |
DECEMBER 31, 2007 | | $ | 260,458 | | | $ | 1,025,149 | | | $ | 831,612 | | | $ | (35,187 | ) | | $ | 2,082,032 | |
| | | | | | | | | | | | | | | | | | | | |
EITF 06-10 Adoption, Net of Tax of $1,175 | | | | | | | | | | | (2,181 | ) | | | | | | | (2,181 | ) |
SFAS 157 Adoption, Net of Tax of $154 | | | | | | | | | | | (286 | ) | | | | | | | (286 | ) |
Capital Contribution from Parent | | | | | | | 75,000 | | | | | | | | | | | | 75,000 | |
Preferred Stock Dividends | | | | | | | | | | | (200 | ) | | | | | | | (200 | ) |
Capital Stock Expense | | | | | | | 39 | | | | (38 | ) | | | | | | | 1 | |
TOTAL | | | | | | | | | | | | | | | | | | | 2,154,366 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $7,438 | | | | | | | | | | | | | | | (13,813 | ) | | | (13,813 | ) |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $449 | | | | | | | | | | | | | | | 833 | | | | 833 | |
NET INCOME | | | | | | | | | | | 55,313 | | | | | | | | 55,313 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 42,333 | |
| | | | | | | | | | | | | | | | | | | | |
MARCH 31, 2008 | | $ | 260,458 | | | $ | 1,100,188 | | | $ | 884,220 | | | $ | (48,167 | ) | | $ | 2,196,699 | |
| | | | | | | | | | | | | | | | | | | | |
DECEMBER 31, 2008 | | $ | 260,458 | | | $ | 1,225,292 | | | $ | 951,066 | | | $ | (60,225 | ) | | $ | 2,376,591 | |
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (20,000 | ) | | | | | | | (20,000 | ) |
Preferred Stock Dividends | | | | | | | | | | | (200 | ) | | | | | | | (200 | ) |
Capital Stock Expense | | | | | | | 26 | | | | (25 | ) | | | | | | | 1 | |
TOTAL | | | | | | | | | | | | | | | | | | | 2,356,392 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $945 | | | | | | | | | | | | | | | 1,756 | | | | 1,756 | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $661 | | | | | | | | | | | | | | | 1,226 | | | | 1,226 | |
NET INCOME | | | | | | | | | | | 74,407 | | | | | | | | 74,407 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 77,389 | |
| | | | | | | | | | | | | | | | | | | | |
MARCH 31, 2009 | | $ | 260,458 | | | $ | 1,225,318 | | | $ | 1,005,248 | | | $ | (57,243 | ) | | $ | 2,433,781 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2008March 31, 2009 and December 31, 20072008
(in thousands)
(Unaudited)
| | 2008 | | | 2007 | | | 2009 | | | 2008 | |
CURRENT ASSETS | | | | | | | | | | | | |
Cash and Cash Equivalents | | $ | 1,987 | | | $ | 2,195 | | | $ | 2,554 | | | $ | 1,996 | |
Accounts Receivable: | | | | | | | | | | | | | | | | |
Customers | | | 204,692 | | | | 176,834 | | | | 158,282 | | | | 175,709 | |
Affiliated Companies | | | 96,277 | | | | 113,582 | | | | 79,998 | | | | 110,982 | |
Accrued Unbilled Revenues | | | 43,333 | | | | 38,397 | | | | 40,347 | | | | 55,733 | |
Miscellaneous | | | 1,923 | | | | 2,823 | | | | 640 | | | | 498 | |
Allowance for Uncollectible Accounts | | | (16,224 | ) | | | (13,948 | ) | | | (6,566 | ) | | | (6,176 | ) |
Total Accounts Receivable | | | 330,001 | | | | 317,688 | | | | 272,701 | | | | 336,746 | |
Fuel | | | 80,853 | | | | 82,203 | | | | 168,257 | | | | 131,239 | |
Materials and Supplies | | | 74,552 | | | | 76,685 | | | | 78,508 | | | | 76,260 | |
Risk Management Assets | | | 81,958 | | | | 62,955 | | | | 75,195 | | | | 65,140 | |
Accrued Tax Benefits | | | | 55,247 | | | | 15,599 | |
Regulatory Asset for Under-Recovered Fuel Costs | | | 90,111 | | | | - | | | | 236,743 | | | | 165,906 | |
Prepayments and Other | | | 60,431 | | | | 16,369 | | | | 48,669 | | | | 45,657 | |
TOTAL | | | 719,893 | | | | 558,095 | | | | 937,874 | | | | 838,543 | |
| | | | | | | | | | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | | | | | | | | | |
Electric: | | | | | | | | | | | | | | | | |
Production | | | 3,655,253 | | | | 3,625,788 | | | | 4,147,818 | | | | 3,708,850 | |
Transmission | | | 1,739,018 | | | | 1,675,081 | | | | 1,769,947 | | | | 1,754,192 | |
Distribution | | | 2,453,323 | | | | 2,372,687 | | | | 2,539,095 | | | | 2,499,974 | |
Other | | | 362,985 | | | | 351,827 | | | | 355,514 | | | | 358,873 | |
Construction Work in Progress | | | 947,101 | | | | 713,063 | | | | 700,084 | | | | 1,106,032 | |
Total | | | 9,157,680 | | | | 8,738,446 | | | | 9,512,458 | | | | 9,427,921 | |
Accumulated Depreciation and Amortization | | | 2,662,328 | | | | 2,591,833 | | | | 2,691,689 | | | | 2,675,784 | |
TOTAL - NET | | | 6,495,352 | | | | 6,146,613 | | | | 6,820,769 | | | | 6,752,137 | |
| | | | | | | | | | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | | | | | | | | | |
Regulatory Assets | | | 712,001 | | | | 652,739 | | | | 1,012,778 | | | | 999,061 | |
Long-term Risk Management Assets | | | 55,199 | | | | 72,366 | | | | 64,771 | | | | 51,095 | |
Deferred Charges and Other | | | 179,054 | | | | 191,871 | | | | 119,665 | | | | 121,828 | |
TOTAL | | | 946,254 | | | | 916,976 | | | | 1,197,214 | | | | 1,171,984 | |
| | | | | | | | | | | | | | | | |
TOTAL ASSETS | | $ | 8,161,499 | | | $ | 7,621,684 | | | $ | 8,955,857 | | | $ | 8,762,664 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2008March 31, 2009 and December 31, 20072008
(Unaudited)
| | 2008 | | | 2007 | | | 2009 | | | 2008 | |
CURRENT LIABILITIES | | (in thousands) | | | (in thousands) | |
Advances from Affiliates | | $ | 93,558 | | | $ | 275,257 | | | $ | 120,481 | | | $ | 194,888 | |
Accounts Payable: | | | | | | | | | | | | | | | | |
General | | | 290,320 | | | | 241,871 | | | | 254,384 | | | | 358,081 | |
Affiliated Companies | | | 105,647 | | | | 106,852 | | | | 97,749 | | | | 206,813 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 150,016 | | | | 239,732 | | | | 150,017 | | | | 150,017 | |
Risk Management Liabilities | | | 75,105 | | | | 51,708 | | | | 39,092 | | | | 30,620 | |
Customer Deposits | | | 51,243 | | | | 45,920 | | | | 57,025 | | | | 54,086 | |
Deferred Income Taxes | | | | 107,721 | | | | - | |
Accrued Taxes | | | 34,154 | | | | 58,519 | | | | 63,997 | | | | 65,550 | |
Accrued Interest | | | 68,110 | | | | 41,699 | | | | 69,518 | | | | 47,804 | |
Other | | | 98,950 | | | | 139,476 | | | | 74,269 | | | | 113,655 | |
TOTAL | | | 967,103 | | | | 1,201,034 | | | | 1,034,253 | | | | 1,221,514 | |
| | | | | | | | | | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 2,873,980 | | | | 2,507,567 | | | | 3,271,191 | | | | 2,924,495 | |
Long-term Debt – Affiliated | | | 100,000 | | | | 100,000 | | | | 100,000 | | | | 100,000 | |
Long-term Risk Management Liabilities | | | 32,775 | | | | 47,357 | | | | 30,055 | | | | 26,388 | |
Deferred Income Taxes | | | 1,073,269 | | | | 948,891 | | | | 1,105,974 | | | | 1,131,164 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 509,068 | | | | 505,556 | | | | 518,038 | | | | 521,508 | |
Employee Benefits and Pension Obligations | | | | 329,245 | | | | 331,000 | |
Deferred Credits and Other | | | 211,735 | | | | 211,495 | | | | 115,568 | | | | 112,252 | |
TOTAL | | | 4,800,827 | | | | 4,320,866 | | | | 5,470,071 | | | | 5,146,807 | |
| | | | | | | | | | | | | | | | |
TOTAL LIABILITIES | | | 5,767,930 | | | | 5,521,900 | | | | 6,504,324 | | | | 6,368,321 | |
| | | | | | | | | | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 17,752 | | | | 17,752 | | | | 17,752 | | | | 17,752 | |
| | | | | | | | | | | | | | | | |
Commitments and Contingencies (Note 4) | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
COMMON SHAREHOLDER’S EQUITY | | | | | | | | | | | | | | | | |
Common Stock – No Par Value: | | | | | | | | | | | | | | | | |
Authorized – 30,000,000 Shares | | | | | | | | | | | | | | | | |
Outstanding – 13,499,500 Shares | | | 260,458 | | | | 260,458 | | | | 260,458 | | | | 260,458 | |
Paid-in Capital | | | 1,200,264 | | | | 1,025,149 | | | | 1,225,318 | | | | 1,225,292 | |
Retained Earnings | | | 949,041 | | | | 831,612 | | | | 1,005,248 | | | | 951,066 | |
Accumulated Other Comprehensive Income (Loss) | | | (33,946 | ) | | | (35,187 | ) | | | (57,243 | ) | | | (60,225 | ) |
TOTAL | | | 2,375,817 | | | | 2,082,032 | | | | 2,433,781 | | | | 2,376,591 | |
| | | | | | | | | | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 8,161,499 | | | $ | 7,621,684 | | | $ | 8,955,857 | | | $ | 8,762,664 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the NineThree Months Ended September 30,March 31, 2009 and 2008 and 2007
(in thousands)
(Unaudited)
| | 2008 | | | 2007 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 120,610 | | | $ | 18,803 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 186,528 | | | | 142,100 | |
Deferred Income Taxes | | | 111,297 | | | | 32,021 | |
Extraordinary Loss, Net of Tax | | | - | | | | 78,763 | |
Carrying Costs Income | | | (38,921 | ) | | | (22,817 | ) |
Allowance for Equity Funds Used During Construction | | | (6,278 | ) | | | (5,442 | ) |
Mark-to-Market of Risk Management Contracts | | | 7,450 | | | | (1,949 | ) |
Change in Other Noncurrent Assets | | | (24,670 | ) | | | (9,185 | ) |
Change in Other Noncurrent Liabilities | | | (12,565 | ) | | | 27,247 | |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | (12,313 | ) | | | (87 | ) |
Fuel, Materials and Supplies | | | 3,483 | | | | (11,387 | ) |
Accounts Payable | | | 41,869 | | | | (38,724 | ) |
Accrued Taxes, Net | | | (51,208 | ) | | | (9,990 | ) |
Accrued Interest | | | 26,411 | | | | 28,596 | |
Fuel Over/Under-Recovery, Net | | | (113,748 | ) | | | 35,770 | |
Other Current Assets | | | (17,202 | ) | | | (21,483 | ) |
Other Current Liabilities | | | (12,298 | ) | | | (20,702 | ) |
Net Cash Flows from Operating Activities | | | 208,445 | | | | 221,534 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (487,797 | ) | | | (537,930 | ) |
Change in Other Cash Deposits, Net | | | (18 | ) | | | (29 | ) |
Change in Advances to Affiliates, Net | | | - | | | | (38,573 | ) |
Proceeds from Sales of Assets | | | 15,786 | | | | 6,713 | |
Other | | | - | | | | (200 | ) |
Net Cash Flows Used for Investing Activities | | | (472,029 | ) | | | (570,019 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Capital Contribution from Parent | | | 175,000 | | | | - | |
Issuance of Long-term Debt – Nonaffiliated | | | 686,512 | | | | 568,778 | |
Change in Advances from Affiliates, Net | | | (181,699 | ) | | | (34,975 | ) |
Retirement of Long-term Debt – Nonaffiliated | | | (412,786 | ) | | | (125,009 | ) |
Retirement of Cumulative Preferred Stock | | | - | | | | (9 | ) |
Principal Payments for Capital Lease Obligations | | | (3,052 | ) | | | (3,316 | ) |
Amortization of Funds from Amended Coal Contract | | | - | | | | (32,433 | ) |
Dividends Paid on Common Stock | | | - | | | | (25,000 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (599 | ) | | | (600 | ) |
Net Cash Flows from Financing Activities | | | 263,376 | | | | 347,436 | |
| | | | | | | | |
Net Decrease in Cash and Cash Equivalents | | | (208 | ) | | | (1,049 | ) |
Cash and Cash Equivalents at Beginning of Period | | | 2,195 | | | | 2,318 | |
Cash and Cash Equivalents at End of Period | | $ | 1,987 | | | $ | 1,269 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 110,349 | | | $ | 86,199 | |
Net Cash Paid (Received) for Income Taxes | | | (26,330 | ) | | | 6,688 | |
Noncash Acquisitions Under Capital Leases | | | 1,246 | | | | 2,738 | |
Construction Expenditures Included in Accounts Payable at September 30, | | | 112,376 | | | | 90,315 | |
| | 2009 | | | 2008 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 74,407 | | | $ | 55,313 | |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 69,995 | | | | 62,572 | |
Deferred Income Taxes | | | 80,375 | | | | 25,066 | |
Carrying Costs Income | | | (4,083 | ) | | | (9,586 | ) |
Allowance for Equity Funds Used During Construction | | | (2,653 | ) | | | (1,496 | ) |
Mark-to-Market of Risk Management Contracts | | | (9,433 | ) | | | (1,658 | ) |
Change in Other Noncurrent Assets | | | (7,737 | ) | | | (13,102 | ) |
Change in Other Noncurrent Liabilities | | | 3,098 | | | | (5,555 | ) |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 64,045 | | | | 32,344 | |
Fuel, Materials and Supplies | | | (39,266 | ) | | | 20,442 | |
Accounts Payable | | | (115,697 | ) | | | 4,235 | |
Accrued Taxes, Net | | | (41,201 | ) | | | (2,942 | ) |
Fuel Over/Under-Recovery, Net | | | (70,837 | ) | | | (26,584 | ) |
Other Current Assets | | | (16,033 | ) | | | (6,690 | ) |
Other Current Liabilities | | | (14,187 | ) | | | (13,527 | ) |
Net Cash Flows from (Used for) Operating Activities | | | (29,207 | ) | | | 118,832 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (221,053 | ) | | | (158,722 | ) |
Change in Other Cash Deposits | | | 235 | | | | - | |
Change in Advances to Affiliates, Net | | | - | | | | (261,823 | ) |
Proceeds from Sales of Assets | | | 228 | | | | 11,366 | |
Net Cash Flows Used for Investing Activities | | | (220,590 | ) | | | (409,179 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Capital Contribution from Parent | | | - | | | | 75,000 | |
Issuance of Long-term Debt – Nonaffiliated | | | 345,814 | | | | 492,325 | |
Change in Advances from Affiliates, Net | | | (74,407 | ) | | | (275,257 | ) |
Retirement of Long-term Debt – Nonaffiliated | | | (4 | ) | | | (3 | ) |
Principal Payments for Capital Lease Obligations | | | (848 | ) | | | (1,061 | ) |
Dividends Paid on Common Stock | | | (20,000 | ) | | | - | |
Dividends Paid on Cumulative Preferred Stock | | | (200 | ) | | | (200 | ) |
Net Cash Flows from Financing Activities | | | 250,355 | | | | 290,804 | |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 558 | | | | 457 | |
Cash and Cash Equivalents at Beginning of Period | | | 1,996 | | | | 2,195 | |
Cash and Cash Equivalents at End of Period | | $ | 2,554 | | | $ | 2,652 | |
SUPPLEMENTARY INFORMATION | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 49,390 | | | $ | 35,527 | |
Net Cash Paid (Received) for Income Taxes | | | (2,683 | ) | | | 338 | |
Noncash Acquisitions Under Capital Leases | | | 151 | | | | 478 | |
Construction Expenditures Included in Accounts Payable at March 31, | | | 88,405 | | | | 83,766 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The condensed notes to APCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to APCo.
| Footnote Reference |
| |
Significant Accounting Matters | Note 1 |
New Accounting Pronouncements and Extraordinary Item | Note 2 |
Rate Matters | Note 3 |
Commitments, Guarantees and Contingencies | Note 4 |
Benefit Plans | Note 65 |
Business Segments | Note 6 |
Derivatives, Hedging and Fair Value Measurements | Note 7 |
Income Taxes | Note 8 |
Financing Activities | Note 9 |
COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
ThirdFirst Quarter of 20082009 Compared to ThirdFirst Quarter of 20072008
Reconciliation of ThirdFirst Quarter of 20072008 to ThirdFirst Quarter of 20082009
Net Income
(in millions)
Third Quarter of 2007 | | | | | $ | 85 | |
| | | | | | | |
Changes in Gross Margin: | | | | | | | |
Retail Margins | | | (4 | ) | | | | |
Off-system Sales | | | 5 | | | | | |
Transmission Revenues | | | 1 | | | | | |
Total Change in Gross Margin | | | | | | | 2 | |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | (2 | ) | | | | |
Depreciation and Amortization | | | (3 | ) | | | | |
Taxes Other Than Income Taxes | | | (3 | ) | | | | |
Interest Expense | | | (1 | ) | | | | |
Other Income | | | 2 | | | | | |
Total Change in Operating Expenses and Other | | | | | | | (7 | ) |
| | | | | | | | |
Income Tax Expense | | | | | | | 2 | |
| | | | | | | | |
Third Quarter of 2008 | | | | | | $ | 82 | |
First Quarter of 2008 | | | | | $ | 76 | |
| | | | | | | |
Changes in Gross Margin: | | | | | | | |
Retail Margins | | | (19 | ) | | | | |
Off-system Sales | | | (23 | ) | | | | |
Total Change in Gross Margin | | | | | | | (42 | ) |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | (11 | ) | | | | |
Depreciation and Amortization | | | 14 | | | | | |
Taxes Other Than Income Taxes | | | (1 | ) | | | | |
Other Income | | | (2 | ) | | | | |
Interest Expense | | | (1 | ) | | | | |
Total Change in Operating Expenses and Other | | | | | | | (1 | ) |
| | | | | | | | |
Income Tax Expense | | | | | | | 16 | |
| | | | | | | | |
First Quarter of 2009 | | | | | | $ | 49 | |
Net Income decreased $3$27 million to $82$49 million in 2008.2009. The key driversdriver of the decrease werewas a $7$42 million increasedecrease in Operating Expenses and Other,Gross Margin, partially offset by a $2 million increase in Gross Margin and a $2$16 million decrease in Income Tax Expense.
The major components of the increasedecrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:
· | Retail Margins decreased $4$19 million primarily due to: |
| · | A $23$14 million decrease as a result of Restructuring Transition Charge (RTC) revenues and their associated offset in residential and commercial revenue primarily duefuel under-recovery in the first quarter of 2009. The PUCO allowed CSPCo to a 12% decrease in cooling degree days andcontinue collecting the outages caused byRTC pending the remnantsimplementation of Hurricane Ike.the new ESP tariffs which did not occur until March 30, 2009. In 2008, RTC revenues were recorded but were offset through the amortization of the transition regulatory assets as discussed below. |
| · | A $20$7 million decrease related to increasedCSPCo’s Unit Power Agreement for AEGCo’s Lawrenceburg Plant. Permission was granted to include in fuel allowance and consumables expenses. CSPCo and OPCo have applied for an active fuel clause in their Ohioas a result of the ESP to be effective January 1, 2009.order. |
| · | A $4$3 million increasedecrease in capacity settlement charges under the Interconnection Agreementindustrial revenue primarily due to a change in relative peak demands.lower load. |
| These decreases were partially offset by a $44by: |
| · | A $5 million increase in fuel margins due to the deferral of fuel costs in 2009. The PUCO’s March 2009 approval of CSPCo’s ESP allows for the recovery of fuel and related costs incurred since January 1, 2009. See “Ohio Electric Security Plan Filings” section of Note 3. |
| · | A $5 million increase related to a net increase innew rates implemented.implemented due to the accrual for March unbilled revenues at higher rates set by the Ohio ESP. |
· | Margins from Off-system Sales increased $5decreased $23 million primarily due to increasedlower physical sales volumes and lower margins driven by higheras a result of lower market prices, partially offset by lowerhigher trading margins. |
Operating Expenses and Other and Income Tax Expense changed between years as follows:
· | Other Operation and Maintenance expenses increased $2 million due to: |
· | A $9 million increase in recoverable PJM costs. |
· | A $4 million increase in recoverable customer account expenses related to the Universal Service Fund for customers who qualify for payment assistance. |
· | A $3 million increase in employee-related expenses. |
| These increases were partially offset by a $15 million decrease resulting from a settlement agreement in the third quarter 2007 related to alleged violations of the NSR provisions of the CAA. The $15 million represents CSPCo’s allocation of the settlement. |
· | Depreciation and Amortization increased $3 million primarily due to a greater depreciation base related to environmental improvements placed in service. |
· | Taxes Other Than Income Taxes increased $3 million due to property tax adjustments. |
· | Income Tax Expense decreased $2 million primarily due to a decrease in pretax book income. |
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
Net Income
(in millions)
Nine Months Ended September 30, 2007 | | | | | $ | 212 | |
| | | | | | | |
Changes in Gross Margin: | | | | | | | |
Retail Margins | | | 36 | | | | | |
Off-system Sales | | | 24 | | | | | |
Transmission Revenues | | | 3 | | | | | |
Total Change in Gross Margin | | | | | | | 63 | |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | (45 | ) | | | | |
Depreciation and Amortization | | | 1 | | | | | |
Taxes Other Than Income Taxes | | | (12 | ) | | | | |
Interest Expense | | | (6 | ) | | | | |
Other Income | | | 5 | | | | | |
Total Change in Operating Expenses and Other | | | | | | | (57 | ) |
| | | | | | | | |
Income Tax Expense | | | | | | | (4 | ) |
| | | | | | | | |
Nine Months Ended September 30, 2008 | | | | | | $ | 214 | |
Net Income increased $2 million to $214 million in 2008. The key drivers of the increase were a $63 million increase in Gross Margin primarily offset by a $57 million increase in Operating Expenses and Other and a $4 million increase in Income Tax Expense.
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:
· | Retail Margins increased $36$11 million primarily due to: |
| · | A $106An $8 million increase in overhead line expenses primarily due to ice and wind storms in the first quarter of 2009. |
| · | An $8 million increase related to a net increase in rates implemented.an obligation to contribute to the “Partnership with Ohio” fund for low income, at-risk customers ordered by the PUCO’s March 2009 approval of CSPCo’s ESP. See “Ohio Electric Security Plan Filings” section of Note 3. |
| · | A $35 million decrease in capacity settlement charges related to CSPCo’s Unit Power Agreement (UPA) for AEGCo’s Lawrenceburg Plant, which began in May 2007, and to the April 2007 acquisition of the Darby Plant. |
| · | A $15$6 million increase in industrial revenue related to higher usage by Ormet.recoverable PJM expenses. |
| These increases were partially offset by: |
| · | A $59An $8 million decrease in expenses related to increasedCSPCo’s Unit Power Agreement for AEGCo’s Lawrenceburg Plant primarily due to the classification of capacity and depreciation to fuel allowance and consumables expenses. CSPCo and OPCo have applied for an active fuel clause in their Ohioaccounts pursuant to the March 2009 ESP to be effective January 1, 2009.order. |
| · | A $35$5 million decrease in residential and commercial revenue primarily due to a 16% decrease in cooling and a 6% decrease in heating degree days.employee-related expenses. |
· | Margins from Off-system Sales increased $24Depreciation and Amortization decreased $14 million primarily due to increased physical sales margins driven by higher prices, partially offset by lower trading margins. |
Operating Expenses and Other and Income Tax Expense changed between years as follows:
· | Other Operation and Maintenance expenses increased $45 million primarily due to: |
| · | A $17 million increasethe completed amortization of transition regulatory assets in recoverable PJM expenses. |
| · | A $13 million increase in expenses related to CSPCo’s UPA for AEGCo’s Lawrenceburg Plant which began in May 2007. |
| · | A $10 million increase in steam plant maintenance expenses primarily related to work performed at the Conesville Plant. |
| · | A $9 million increase in recoverable customer account expenses related to the Universal Service Fund for customers who qualify for payment assistance. |
| · | A $4 million increase in boiler plant removal expenses primarily related to work performed at the Conesville Plant. |
| These increases were partially offset by a $15 million decrease resulting from a settlement agreement in the third quarter 2007 related to alleged violations of the NSR provisions of the CAA. The $15 million represents CSPCo’s allocation of the settlement. |
· | Taxes Other Than Income Taxes increased $12 million due to property tax adjustments. |
· | Interest Expense increased $6 million due to increased long-term borrowings. |
· | Other Income increased $5 million primarily due to interest income on federal tax refunds.December 2008. |
· | Income Tax Expense increased $4decreased $16 million primarily due to an increasea decrease in pretax book income and state income taxes.income. |
Critical Accounting Estimates
See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 20072008 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.
Adoption of New Accounting Pronouncements
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Market Risks
Risk management assets and liabilities are managed by AEPSC as agent. The related risk management policies and procedures are instituted and administered by AEPSC. See complete discussion and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.
Interest Rate Risk
Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which CSPCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months. The estimated EaR on CSPCo’s debt portfolio was $1.3$1.4 million.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30,March 31, 2009 and 2008 and 2007
(in thousands)
(Unaudited)
| | Three Months Ended | | | Nine Months Ended | |
| | 2008 | | | 2007 | | | 2008 | | | 2007 | |
REVENUES | | | | | | | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 633,325 | | | $ | 553,518 | | | $ | 1,638,705 | | | $ | 1,446,632 | |
Sales to AEP Affiliates | | | 29,032 | | | | 52,331 | | | | 111,553 | | | | 110,700 | |
Other | | | 1,426 | | | | 1,292 | | | | 4,121 | | | | 3,743 | |
TOTAL | | | 663,783 | | | | 607,141 | | | | 1,754,379 | | | | 1,561,075 | |
| | | | | | | | | | | | | | | | |
EXPENSES | | | | | | | | | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 112,566 | | | | 103,560 | | | | 283,946 | | | | 255,764 | |
Purchased Electricity for Resale | | | 63,441 | | | | 49,619 | | | | 150,637 | | | | 113,765 | |
Purchased Electricity from AEP Affiliates | | | 139,017 | | | | 107,386 | | | | 343,699 | | | | 278,715 | |
Other Operation | | | 87,358 | | | | 83,625 | | | | 245,379 | | | | 207,300 | |
Maintenance | | | 23,039 | | | | 24,250 | | | | 80,705 | | | | 73,537 | |
Depreciation and Amortization | | | 50,373 | | | | 47,589 | | | | 146,668 | | | | 147,332 | |
Taxes Other Than Income Taxes | | | 44,533 | | | | 41,382 | | | | 130,078 | | | | 117,760 | |
TOTAL | | | 520,327 | | | | 457,411 | | | | 1,381,112 | | | | 1,194,173 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 143,456 | | | | 149,730 | | | | 373,267 | | | | 366,902 | |
| | | | | | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | | | | | |
Interest Income | | | 1,515 | | | | 166 | | | | 5,457 | | | | 782 | |
Carrying Costs Income | | | 1,566 | | | | 1,261 | | | | 4,870 | | | | 3,492 | |
Allowance for Equity Funds Used During Construction | | | 745 | | | | 738 | | | | 2,165 | | | | 2,130 | |
Interest Expense | | | (21,127 | ) | | | (19,530 | ) | | | (57,612 | ) | | | (51,193 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 126,155 | | | | 132,365 | | | | 328,147 | | | | 322,113 | |
| | | | | | | | | | | | | | | | |
Income Tax Expense | | | 44,493 | | | | 46,911 | | | | 113,939 | | | | 109,656 | |
| | | | | | | | | | | | | | | | |
NET INCOME | | | 81,662 | | | | 85,454 | | | | 214,208 | | | | 212,457 | |
| | | | | | | | | | | | | | | | |
Capital Stock Expense | | | 39 | | | | 39 | | | | 118 | | | | 118 | |
| | | | | | | | | | | | | | | | |
EARNINGS APPLICABLE TO COMMON STOCK | | $ | 81,623 | | | $ | 85,415 | | | $ | 214,090 | | | $ | 212,339 | |
| | 2009 | | | 2008 | |
REVENUES | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 460,922 | | | $ | 505,324 | |
Sales to AEP Affiliates | | | 10,206 | | | | 35,108 | |
Other | | | 608 | | | | 1,217 | |
TOTAL | | | 471,736 | | | | 541,649 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 70,944 | | | | 85,127 | |
Purchased Electricity for Resale | | | 29,838 | | | | 42,186 | |
Purchased Electricity from AEP Affiliates | | | 93,092 | | | | 94,104 | |
Other Operation | | | 76,088 | | | | 73,066 | |
Maintenance | | | 31,014 | | | | 23,231 | |
Depreciation and Amortization | | | 34,945 | | | | 48,602 | |
Taxes Other Than Income Taxes | | | 45,282 | | | | 44,556 | |
TOTAL | | | 381,203 | | | | 410,872 | |
| | | | | | | | |
OPERATING INCOME | | | 90,533 | | | | 130,777 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest Income | | | 240 | | | | 2,339 | |
Carrying Costs Income | | | 1,689 | | | | 1,766 | |
Allowance for Equity Funds Used During Construction | | | 1,300 | | | | 855 | |
Interest Expense | | | (20,793 | ) | | | (19,239 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 72,969 | | | | 116,498 | |
| | | | | | | | |
Income Tax Expense | | | 24,111 | | | | 40,345 | |
| | | | | | | | |
NET INCOME | | | 48,858 | | | | 76,153 | |
| | | | | | | | |
Capital Stock Expense | | | 39 | | | | 39 | |
| | | | | | | | |
EARNINGS ATTRIBUTABLE TO COMMON STOCK | | $ | 48,819 | | | $ | 76,114 | |
The common stock of CSPCo is wholly-owned by AEP. |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the NineThree Months Ended September 30,March 31, 2009 and 2008 and 2007
(in thousands)
(Unaudited)
| | Common Stock | | | Paid-in Capital | | | Retained Earnings | | | Accumulated Other Comprehensive Income (Loss) | | | Total | |
DECEMBER 31, 2006 | | $ | 41,026 | | | $ | 580,192 | | | $ | 456,787 | | | $ | (21,988 | ) | | $ | 1,056,017 | |
| | | | | | | | | | | | | | | | | | | | |
FIN 48 Adoption, Net of Tax | | | | | | | | | | | (3,022 | ) | | | | | | | (3,022 | ) |
Common Stock Dividends | | | | | | | | | | | (90,000 | ) | | | | | | | (90,000 | ) |
Capital Stock Expense and Other | | | | | | | 118 | | | | (118 | ) | | | | | | | - | |
TOTAL | | | | | | | | | | | | | | | | | | | 962,995 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Loss, Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $1,231 | | | | | | | | | | | | | | | (2,285 | ) | | | (2,285 | ) |
NET INCOME | | | | | | | | | | | 212,457 | | | | | | | | 212,457 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 210,172 | |
| | | | | | | | | | | | | | | | | | | | |
SEPTEMBER 30, 2007 | | $ | 41,026 | | | $ | 580,310 | | | $ | 576,104 | | | $ | (24,273 | ) | | $ | 1,173,167 | |
| | | | | | | | | | | | | | | | | | | | |
DECEMBER 31, 2007 | | $ | 41,026 | | | $ | 580,349 | | | $ | 561,696 | | | $ | (18,794 | ) | | $ | 1,164,277 | |
| | | | | | | | | | | | | | | | | | | | |
EITF 06-10 Adoption, Net of Tax of $589 | | | | | | | | | | | (1,095 | ) | | | | | | | (1,095 | ) |
SFAS 157 Adoption, Net of Tax of $170 | | | | | | | | | | | (316 | ) | | | | | | | (316 | ) |
Common Stock Dividends | | | | | | | | | | | (87,500 | ) | | | | | | | (87,500 | ) |
Capital Stock Expense | | | | | | | 118 | | | | (118 | ) | | | | | | | - | |
TOTAL | | | | | | | | | | | | | | | | | | | 1,075,366 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $582 | | | | | | | | | | | | | | | 1,080 | | | | 1,080 | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $456 | | | | | | | | | | | | | | | 846 | | | | 846 | |
NET INCOME | | | | | | | | | | | 214,208 | | | | | | | | 214,208 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 216,134 | |
| | | | | | | | | | | | | | | | | | | | |
SEPTEMBER 30, 2008 | | $ | 41,026 | | | $ | 580,467 | | | $ | 686,875 | | | $ | (16,868 | ) | | $ | 1,291,500 | |
| | Common Stock | | | Paid-in Capital | | | Retained Earnings | | | Accumulated Other Comprehensive Income (Loss) | | | Total | |
| | | | | | | | | | | | | | | |
DECEMBER 31, 2007 | | $ | 41,026 | | | $ | 580,349 | | | $ | 561,696 | | | $ | (18,794 | ) | | $ | 1,164,277 | |
| | | | | | | | | | | | | | | | | | | | |
EITF 06-10 Adoption, Net of Tax of $589 | | | | | | | | | | | (1,095 | ) | | | | | | | (1,095 | ) |
SFAS 157 Adoption, Net of Tax of $170 | | | | | | | | | | | (316 | ) | | | | | | | (316 | ) |
Common Stock Dividends | | | | | | | | | | | (37,500 | ) | | | | | | | (37,500 | ) |
Capital Stock Expense | | | | | | | 39 | | | | (39 | ) | | | | | | | - | |
TOTAL | | | | | | | | | | | | | | | | | | | 1,125,366 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $3,553 | | | | | | | | | | | | | | | (6,598 | ) | | | (6,598 | ) |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $152 | | | | | | | | | | | | | | | 283 | | | | 283 | |
NET INCOME | | | | | | | | | | | 76,153 | | | | | | | | 76,153 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 69,838 | |
| | | | | | | | | | | | | | | | | | | | |
MARCH 31, 2008 | | $ | 41,026 | | | $ | 580,388 | | | $ | 598,899 | | | $ | (25,109 | ) | | $ | 1,195,204 | |
| | | | | | | | | | | | | | | | | | | | |
DECEMBER 31, 2008 | | $ | 41,026 | | | $ | 580,506 | | | $ | 674,758 | | | $ | (51,025 | ) | | $ | 1,245,265 | |
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (50,000 | ) | | | | | | | (50,000 | ) |
Capital Stock Expense | | | | | | | 39 | | | | (39 | ) | | | | | | | - | |
TOTAL | | | | | | | | | | | | | | | | | | | 1,195,265 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $340 | | | | | | | | | | | | | | | 631 | | | | 631 | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $298 | | | | | | | | | | | | | | | 554 | | | | 554 | |
NET INCOME | | | | | | | | | | | 48,858 | | | | | | | | 48,858 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 50,043 | |
| | | | | | | | | | | | | | | | | | | | |
MARCH 31, 2009 | | $ | 41,026 | | | $ | 580,545 | | | $ | 673,577 | | | $ | (49,840 | ) | | $ | 1,245,308 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2008March 31, 2009 and December 31, 20072008
(in thousands)
(Unaudited)
| | 2008 | | | 2007 | | | 2009 | | | 2008 | |
CURRENT ASSETS | | | | | | | | | | | | |
Cash and Cash Equivalents | | $ | 1,956 | | | $ | 1,389 | | | $ | 1,287 | | | $ | 1,063 | |
Other Cash Deposits | | | 31,964 | | | | 53,760 | | | | 21,207 | | | | 32,300 | |
Advances to Affiliates | | | 21,833 | | | | - | | |
Accounts Receivable: | | | | | | | | | | | | | | | | |
Customers | | | 65,581 | | | | 57,268 | | | | 47,321 | | | | 56,008 | |
Affiliated Companies | | | 27,933 | | | | 32,852 | | | | 14,651 | | | | 44,235 | |
Accrued Unbilled Revenues | | | 24,078 | | | | 14,815 | | | | 11,795 | | | | 18,359 | |
Miscellaneous | | | 11,256 | | | | 9,905 | | | | 13,216 | | | | 11,546 | |
Allowance for Uncollectible Accounts | | | (2,814 | ) | | | (2,563 | ) | | | (3,075 | ) | | | (2,895 | ) |
Total Accounts Receivable | | | 126,034 | | | | 112,277 | | | | 83,908 | | | | 127,253 | |
Fuel | | | 30,081 | | | | 35,849 | | | | 60,690 | | | | 42,075 | |
Materials and Supplies | | | 34,979 | | | | 36,626 | | | | 35,020 | | | | 33,781 | |
Emission Allowances | | | 7,884 | | | | 16,811 | | | | 18,042 | | | | 20,211 | |
Risk Management Assets | | | 40,842 | | | | 33,558 | | | | 39,587 | | | | 35,984 | |
Margin Deposits | | | | 21,098 | | | | 13,613 | |
Prepayments and Other | | | 31,984 | | | | 9,960 | | | | 29,445 | | | | 27,880 | |
TOTAL | | | 327,557 | | | | 300,230 | | | | 310,284 | | | | 334,160 | |
| | | | | | | | | | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | | | | | | | | | |
Electric: | | | | | | | | | | | | | | | | |
Production | | | 2,317,357 | | | | 2,072,564 | | | | 2,343,392 | | | | 2,326,056 | |
Transmission | | | 568,380 | | | | 510,107 | | | | 577,746 | | | | 574,018 | |
Distribution | | | 1,600,323 | | | | 1,552,999 | | | | 1,651,218 | | | | 1,625,000 | |
Other | | | 211,475 | | | | 198,476 | | | | 208,511 | | | | 211,088 | |
Construction Work in Progress | | | 322,885 | | | | 415,327 | | | | 406,619 | | | | 394,918 | |
Total | | | 5,020,420 | | | | 4,749,473 | | | | 5,187,486 | | | | 5,131,080 | |
Accumulated Depreciation and Amortization | | | 1,758,415 | | | | 1,697,793 | | | | 1,802,510 | | | | 1,781,866 | |
TOTAL - NET | | | 3,262,005 | | | | 3,051,680 | | | | 3,384,976 | | | | 3,349,214 | |
| | | | | | | | | | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | | | | | | | | | |
Regulatory Assets | | | 204,203 | | | | 235,883 | | | | 314,200 | | | | 298,357 | |
Long-term Risk Management Assets | | | 30,268 | | | | 41,852 | | | | 34,308 | | | | 28,461 | |
Deferred Charges and Other | | | 125,071 | | | | 181,563 | | | | 109,452 | | | | 125,814 | |
TOTAL | | | 359,542 | | | | 459,298 | | | | 457,960 | | | | 452,632 | |
| | | | | | | | | | | | | | | | |
TOTAL ASSETS | | $ | 3,949,104 | | | $ | 3,811,208 | | | $ | 4,153,220 | | | $ | 4,136,006 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDER’S EQUITY
September 30, 2008March 31, 2009 and December 31, 20072008
(Unaudited)
| | 2009 | | | 2008 | |
CURRENT LIABILITIES | | (in thousands) | |
Advances from Affiliates | | $ | 177,736 | | | $ | 74,865 | |
Accounts Payable: | | | | | | | | |
General | | | 121,022 | | | | 131,417 | |
Affiliated Companies | | | 53,594 | | | | 120,420 | |
Long-term Debt Due Within One Year – Affiliated | | | 100,000 | | | | - | |
Risk Management Liabilities | | | 20,561 | | | | 16,490 | |
Customer Deposits | | | 31,724 | | | | 30,145 | |
Accrued Taxes | | | 141,470 | | | | 185,293 | |
Other | | | 82,399 | | | | 82,678 | |
TOTAL | | | 728,506 | | | | 641,308 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 1,343,696 | | | | 1,343,594 | |
Long-term Debt – Affiliated | | | - | | | | 100,000 | |
Long-term Risk Management Liabilities | | | 15,923 | | | | 14,774 | |
Deferred Income Taxes | | | 457,433 | | | | 435,773 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 164,955 | | | | 161,102 | |
Employee Benefits and Pension Obligations | | | 146,009 | | | | 148,123 | |
Deferred Credits and Other | | | 51,390 | | | | 46,067 | |
TOTAL | | | 2,179,406 | | | | 2,249,433 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 2,907,912 | | | | 2,890,741 | |
| | | | | | | | |
Commitments and Contingencies (Note 4) | | | | | | | | |
| | | | | | | | |
COMMON SHAREHOLDER’S EQUITY | | | | | | | | |
Common Stock – No Par Value: | | | | | | | | |
Authorized – 24,000,000 Shares | | | | | | | | |
Outstanding – 16,410,426 Shares | | | 41,026 | | | | 41,026 | |
Paid-in Capital | | | 580,545 | | | | 580,506 | |
Retained Earnings | | | 673,577 | | | | 674,758 | |
Accumulated Other Comprehensive Income (Loss) | | | (49,840 | ) | | | (51,025 | ) |
TOTAL | | | 1,245,308 | | | | 1,245,265 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY | | $ | 4,153,220 | | | $ | 4,136,006 | |
| | 2008 | | | 2007 | |
CURRENT LIABILITIES | | (in thousands) | |
Advances from Affiliates | | $ | - | | | $ | 95,199 | |
Accounts Payable: | | | | | | | | |
General | | | 145,733 | | | | 113,290 | |
Affiliated Companies | | | 53,532 | | | | 65,292 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | - | | | | 112,000 | |
Risk Management Liabilities | | | 37,331 | | | | 28,237 | |
Customer Deposits | | | 29,995 | | | | 43,095 | |
Accrued Taxes | | | 153,391 | | | | 179,831 | |
Other | | | 84,432 | | | | 96,892 | |
TOTAL | | | 504,414 | | | | 733,836 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 1,343,491 | | | | 1,086,224 | |
Long-term Debt – Affiliated | | | 100,000 | | | | 100,000 | |
Long-term Risk Management Liabilities | | | 18,061 | | | | 27,419 | |
Deferred Income Taxes | | | 447,465 | | | | 437,306 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 155,332 | | | | 165,635 | |
Deferred Credits and Other | | | 88,841 | | | | 96,511 | |
TOTAL | | | 2,153,190 | | | | 1,913,095 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 2,657,604 | | | | 2,646,931 | |
| | | | | | | | |
Commitments and Contingencies (Note 4) | | | | | | | | |
| | | | | | | | |
COMMON SHAREHOLDER’S EQUITY | | | | | | | | |
Common Stock – No Par Value: | | | | | | | | |
Authorized – 24,000,000 Shares | | | | | | | | |
Outstanding – 16,410,426 Shares | | | 41,026 | | | | 41,026 | |
Paid-in Capital | | | 580,467 | | | | 580,349 | |
Retained Earnings | | | 686,875 | | | | 561,696 | |
Accumulated Other Comprehensive Income (Loss) | | | (16,868 | ) | | | (18,794 | ) |
TOTAL | | | 1,291,500 | | | | 1,164,277 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDER’S EQUITY | | $ | 3,949,104 | | | $ | 3,811,208 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the NineThree Months Ended September 30,March 31, 2009 and 2008 and 2007
(in thousands)
(Unaudited)
| | 2009 | | | 2008 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 48,858 | | | $ | 76,153 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 34,945 | | | | 48,602 | |
Deferred Income Taxes | | | 38,945 | | | | 872 | |
Allowance for Equity Funds Used During Construction | | | (1,300 | ) | | | (855 | ) |
Mark-to-Market of Risk Management Contracts | | | (3,204 | ) | | | (1,499 | ) |
Deferred Property Taxes | | | 22,262 | | | | 21,728 | |
Fuel Over/Under-Recovery, Net | | | (16,934 | ) | | | - | |
Change in Other Noncurrent Assets | | | (8,551 | ) | | | (11,440 | ) |
Change in Other Noncurrent Liabilities | | | 13,410 | | | | 1,292 | |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 43,345 | | | | (3,383 | ) |
Fuel, Materials and Supplies | | | (19,854 | ) | | | 6,485 | |
Accounts Payable | | | (81,080 | ) | | | (6,756 | ) |
Accrued Taxes, Net | | | (57,623 | ) | | | (2,001 | ) |
Other Current Assets | | | 1,157 | | | | (2,211 | ) |
Other Current Liabilities | | | (9,817 | ) | | | (20,972 | ) |
Net Cash Flows from Operating Activities | | | 4,559 | | | | 106,015 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (67,831 | ) | | | (84,513 | ) |
Change in Other Cash Deposits | | | 11,093 | | | | - | |
Proceeds from Sales of Assets | | | 206 | | | | 150 | |
Net Cash Flows Used for Investing Activities | | | (56,532 | ) | | | (84,363 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Change in Advances from Affiliates, Net | | | 102,871 | | | | 68,800 | |
Retirement of Long-term Debt – Nonaffiliated | | | - | | | | (52,000 | ) |
Principal Payments for Capital Lease Obligations | | | (674 | ) | | | (725 | ) |
Dividends Paid on Common Stock | | | (50,000 | ) | | | (37,500 | ) |
Net Cash Flows from (Used for) Financing Activities | | | 52,197 | | | | (21,425 | ) |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 224 | | | | 227 | |
Cash and Cash Equivalents at Beginning of Period | | | 1,063 | | | | 1,389 | |
Cash and Cash Equivalents at End of Period | | $ | 1,287 | | | $ | 1,616 | |
| | 2008 | | | 2007 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 214,208 | | | $ | 212,457 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 146,668 | | | | 147,332 | |
Deferred Income Taxes | | | 8,981 | | | | (13,959 | ) |
Carrying Costs Income | | | (4,870 | ) | | | (3,492 | ) |
Allowance for Equity Funds Used During Construction | | | (2,165 | ) | | | (2,130 | ) |
Mark-to-Market of Risk Management Contracts | | | 5,326 | | | | 1,321 | |
Deferred Property Taxes | | | 65,763 | | | | 57,890 | |
Change in Other Noncurrent Assets | | | (7,942 | ) | | | (29,199 | ) |
Change in Other Noncurrent Liabilities | | | (4,081 | ) | | | 2,713 | |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | (13,757 | ) | | | (13,040 | ) |
Fuel, Materials and Supplies | | | 7,415 | | | | (2,332 | ) |
Accounts Payable | | | (2,650 | ) | | | (13,336 | ) |
Customer Deposits | | | (13,100 | ) | | | 10,212 | |
Accrued Taxes, Net | | | (26,358 | ) | | | (44,295 | ) |
Other Current Assets | | | (13,178 | ) | | | (1,490 | ) |
Other Current Liabilities | | | (14,018 | ) | | | 8,817 | |
Net Cash Flows from Operating Activities | | | 346,242 | | | | 317,469 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (304,175 | ) | | | (246,130 | ) |
Change in Other Cash Deposits, Net | | | 21,796 | | | | (44,360 | ) |
Change in Advances to Affiliates, Net | | | (21,833 | ) | | | - | |
Acquisition of Darby Plant | | | - | | | | (102,032 | ) |
Proceeds from Sales of Assets | | | 1,287 | | | | 1,016 | |
Net Cash Flows Used for Investing Activities | | | (302,925 | ) | | | (391,506 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Long-term Debt – Nonaffiliated | | | 346,407 | | | | 44,257 | |
Change in Advances from Affiliates, Net | | | (95,199 | ) | | | 122,347 | |
Retirement of Long-term Debt – Nonaffiliated | | | (204,245 | ) | | | - | |
Principal Payments for Capital Lease Obligations | | | (2,213 | ) | | | (2,191 | ) |
Dividends Paid on Common Stock | | | (87,500 | ) | | | (90,000 | ) |
Net Cash Flows from (Used for) Financing Activities | | | (42,750 | ) | | | 74,413 | |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 567 | | | | 376 | |
Cash and Cash Equivalents at Beginning of Period | | | 1,389 | | | | 1,319 | |
Cash and Cash Equivalents at End of Period | | $ | 1,956 | | | $ | 1,695 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 57,004 | | | $ | 53,464 | |
Net Cash Paid for Income Taxes | | | 53,682 | | | | 93,709 | |
Noncash Acquisitions Under Capital Leases | | | 1,374 | | | | 1,900 | |
Construction Expenditures Included in Accounts Payable at September 30, | | | 51,997 | | | | 34,630 | |
Noncash Assumption of Liabilities Related to Acquisition of Darby Plant | | | - | | | | 2,339 | |
SUPPLEMENTARY INFORMATION | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 31,229 | | | $ | 24,351 | |
Net Cash Paid for Income Taxes | | | 387 | | | | 2,494 | |
Noncash Acquisitions Under Capital Leases | | | 254 | | | | 355 | |
Construction Expenditures Included in Accounts Payable at March 31, | | | 51,297 | | | | 48,392 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES
The condensed notes to CSPCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to CSPCo.
| Footnote Reference |
| |
Significant Accounting Matters | Note 1 |
New Accounting Pronouncements and Extraordinary Item | Note 2 |
Rate Matters | Note 3 |
Commitments, Guarantees and Contingencies | Note 4 |
AcquisitionBenefit Plans | Note 5 |
Benefit PlansBusiness Segments | Note 6 |
Business SegmentsDerivatives, Hedging and Fair Value Measurements | Note 7 |
Income Taxes | Note 8 |
Financing Activities | Note 9 |
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
ThirdFirst Quarter of 20082009 Compared to ThirdFirst Quarter of 20072008
Reconciliation of ThirdFirst Quarter of 20072008 to ThirdFirst Quarter of 20082009
Net Income
(in millions)
Third Quarter of 2007 | | | | | $ | 49 | |
| | | | | | | |
Changes in Gross Margin: | | | | | | | |
Retail Margins | | | (16 | ) | | | | |
FERC Municipals and Cooperatives | | | (2 | ) | | | | |
Off-system Sales | | | 4 | | | | | |
Other | | | 10 | | | | | |
Total Change in Gross Margin | | | | | | | (4 | ) |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | (2 | ) | | | | |
Depreciation and Amortization | | | 4 | | | | | |
Other Income | | | (1 | ) | | | | |
Interest Expense | | | (2 | ) | | | | |
Total Change in Operating Expenses and Other | | | | | | | (1 | ) |
| | | | | | | | |
Income Tax Expense | | | | | | | 2 | |
| | | | | | | | |
Third Quarter of 2008 | | | | | | $ | 46 | |
Net Income decreased $3 million to $46 million in 2008. The key drivers of the decrease were a $4 million decrease in Gross Margin and a $1 million increase in Operating Expenses and Other, partially offset by a $2 million decrease in Income Tax Expense.
The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:
· | Retail Margins decreased $16 million primarily due to lower retail sales reflecting weather conditions as cooling degree days decreased at least 12% in both the Indiana and Michigan jurisdictions. |
· | Margins from Off-system Sales increased $4 million primarily due to increased physical sales margins driven by higher prices, partially offset by lower trading margins. |
· | Other revenues increased $10 million primarily due to increased River Transportation Division (RTD) revenues for barging services. RTD’s related expenses which offset the RTD revenue increase are included in Other Operation on the Condensed Consolidated Statements of Income resulting in earning only a return approved under a regulatory order. |
Operating Expenses and Other and Income Tax Expense changed between years as follows:
· | Other Operation and Maintenance expenses increased $2 million primarily due to higher operation and maintenance expenses for RTD of $11 million caused by increased barging activity and increased cost of fuel in 2008, partially offset by a $9 million decrease in coal-fired plant operation expenses. A settlement agreement related to alleged violations of the NSR provisions of the CAA, of which $14 million was allocated to I&M, increased 2007 Other Operation and Maintenance expenses. |
· | Depreciation and Amortization expense decreased $4 million primarily due to reduced depreciation rates reflecting longer estimated lives for Cook and Tanners Creek Plants. Depreciation rates were reduced for the FERC and Michigan jurisdictions in October 2007. See “Michigan Depreciation Study Filing” section of Note 4 in the 2007 Annual Report. |
· | Income Tax Expense decreased $2 million primarily due to a decrease in pretax book income. |
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
Net Income
(in millions)
Nine Months Ended September 30, 2007 | | | | | $ | 109 | | |
First Quarter of 2008 | | | | | | $ | 55 | |
| | | | | | | | | | | | |
Changes in Gross Margin: | | | | | | | | | | | | | |
Retail Margins | | | (19 | ) | | | | | | (3 | ) | | | | |
FERC Municipals and Cooperatives | | | 4 | | | | | | (1 | ) | | | | |
Off-system Sales | | | 18 | | | | | | (27 | ) | | | | |
Transmission Revenues | | | (2 | ) | | | | | | (1 | ) | | | | |
Other | | | 31 | | | | | | 56 | | | | | |
Total Change in Gross Margin | | | | | 32 | | | | | | | | 24 | |
| | | | | | | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | | | | | | | |
Other Operation and Maintenance | | | (24 | ) | | | | | | 16 | | | | | |
Depreciation and Amortization | | | 50 | | | | | | (1 | ) | | | | |
Taxes Other Than Income Taxes | | | (3 | ) | | | | | | (1 | ) | | | | |
Other Income | | | | 2 | | | | | |
Interest Expense | | | | (4 | ) | | | | |
Total Change in Operating Expenses and Other | | | | | 23 | | | | | | | | 12 | |
| | | | | | | | | | | | | |
Income Tax Expense | | | | | | (13 | ) | | | | | | | (10 | ) |
| | | | | | | | | | | | | |
Nine Months Ended September 30, 2008 | | | | | $ | 151 | | |
First Quarter of 2009 | | | | | | | $ | 81 | |
Net Income increased $42$26 million to $151$81 million in 2008.2009. The key drivers of the increase were a $32$24 million increase in Gross Margin and a $23$12 million decrease in Operating Expenses and Other, partially offset by a $13$10 million increase in Income Tax Expense.
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:
· | Retail Margins decreased $19$3 million primarily due to lower retaila $14 million decline in industrial margins due to a 21% decrease in industrial sales, partially offset by a $9 million increase in capacity revenue reflecting weather conditions as cooling degree days decreased at least 19% in both the Indiana and Michigan jurisdictions.MLR changes. |
· | Margins from Off-system Sales increased $18decreased $27 million primarily due to increasedlower physical sales volumes and lower margins driven by higher prices, partially offset byas a result of lower trading margins.market prices. |
· | Other revenuesRevenues increased $31$56 million primarily due to increased RTD revenues for barging services. RTD’s related expensesCook Plant accidental outage insurance policy proceeds of $54 million. Of these insurance proceeds, $20 million were used to offset fuel costs associated with the Cook Plant Unit 1 shutdown which offset the RTD revenue increase are primarily included in Other Operation on the Condensed Consolidated StatementsRetail Margins. See “Cook Plant Unit 1 Fire and Shutdown” section of Income resulting in earning only a return approved under regulatory order.Note 4. |
Operating Expenses and Other and Income Tax Expense changed between years as follows:
· | Other Operation and Maintenance expenses increased $24decreased $16 million primarily due to higher operationlower nuclear and maintenance expensescoal production, transmission and distribution costs and deferral of NSR and OPEB costs included in the rate settlement for RTDrecovery. See “Indiana Base Rate Filing” section of $31 million caused by increased barging activity and increased cost of fuel and an increase in nuclear operation and maintenance expenses of $16 million. Lower coal-fired plant operation and maintenance expenses of $18 million, including the NSR settlement, and a $5 million decrease in accretion expense partially offset the increases.Note 3. |
· | Depreciation and Amortization expense decreased $50Interest Expense increased $4 million primarily due to the reduced depreciation rates in all jurisdictions. Depreciation rates were reduced for the Indiana jurisdiction in June 2007 and the FERC and Michigan jurisdictions in October 2007. See “Indiana Depreciation Study Filing” and “Michigan Depreciation Study Filing” sectionsincreased borrowings. In January 2009, I&M issued $475 million of Note 4 in the 2007 Annual Report.7% senior unsecured notes. |
· | Income Tax Expense increased $13$10 million primarily due to an increase in pretax book income and a decrease in amortization of investment tax credits, partially offset by changes in certain book/tax differences accounted for on a flow-through basis.income. |
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 Cook Plant Unit 1 (Unit 1) due to turbine vibrations, likely caused by blade failure, which resulted in a fire on the electric generator. This equipment, islocated in the turbine building, and is separate and isolated from the nuclear reactor. The steam turbinesturbine rotors that caused the vibration were installed in 2006 and are underwithin the vendor’s warranty from the vendor.period. The warranty provides for the repair or replacement of the turbinesturbine rotors if the damage was caused by a defect in the designmaterials or assembly of the turbines.workmanship. I&M is also working with its insurance company, Nuclear Electric Insurance Limited (NEIL), and its turbine vendor, Siemens, to evaluate the extent of the damage resulting from the incident and the costsfacilitate repairs to return the unit to service. Management cannot estimate the ultimate costsRepair of the outage at this time.property damage and replacement of the turbine rotors and other equipment could cost up to approximately $330 million. Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process. Management's preliminary analysis indicates thatThe treatment of property damage costs, replacement power costs and insurance proceeds will be the subject of future regulatory proceedings in Indiana and Michigan. I&M is repairing Unit 1 couldto resume operations as early as late first quarter/early second quarterOctober 2009 at reduced power. Should post-repair operations prove unsuccessful, the replacement of 2009 or as late asparts will extend the second half of 2009, depending upon whether the damaged components can be repaired or whether they need to be replaced.outage into 2011.
I&M maintains property insurance through NEIL with a $1 million deductible. As of March 31, 2009, I&M recorded $34 million in Prepayments and Other on the Condensed Consolidated Balance Sheets representing recoverable amounts under the property insurance policy. I&M received partial reimbursements from NEIL for the cost incurred to date to repair the property damage. I&M also maintains a separate accidental outage policy with NEIL whereby, after a 12 week12-week deductible period, I&M is entitled to weekly payments of $3.5 million duringfor the first 52 weeks following the deductible period. After the initial 52 weeks of indemnity, the policy pays $2.8 million per week for up to an additional 110 weeks. I&M began receiving payments under the accidental outage period for a covered loss.policy in December 2008. In the first quarter of 2009, I&M recorded $54 million in revenues, including $9 million in revenues that were deferred at December 31, 2008, related to the accidental outage policy. In order to hold customers harmless, in the first quarter of 2009, I&M applied $20 million of the accidental outage insurance proceeds to reduce fuel underrecoveries reflecting recoverable fuel costs as if Unit 1 were operating. 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.
Critical Accounting Estimates
See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 20072008 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.
Adoption of New Accounting Pronouncements
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Market Risks
Risk management assets and liabilities are managed by AEPSC as agent. The related risk management policies and procedures are instituted and administered by AEPSC. See complete discussion and analysis within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section for disclosures about risk management activities.
Interest Rate Risk
Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which I&M’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-termshort- term debt) as well as long-term debt issuances in the next twelve months. The estimated EaR on I&M’s debt portfolio was $5.7$4.5 million.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30,March 31, 2009 and 2008 and 2007
(in thousands)
(Unaudited)
| | Three Months Ended | | | Nine Months Ended | |
| | 2008 | | | 2007 | | | 2008 | | | 2007 | |
REVENUES | | | | | | | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 513,548 | | | $ | 478,907 | | | $ | 1,370,158 | | | $ | 1,286,223 | |
Sales to AEP Affiliates | | | 72,295 | | | | 56,262 | | | | 232,734 | | | | 186,653 | |
Other – Affiliated | | | 31,792 | | | | 16,250 | | | | 84,268 | | | | 43,488 | |
Other – Nonaffiliated | | | 3,388 | | | | 7,757 | | | | 13,659 | | | | 21,718 | |
TOTAL | | | 621,023 | | | | 559,176 | | | | 1,700,819 | | | | 1,538,082 | |
| | | | | | | | | | | | | | | | |
EXPENSES | | | | | | | | | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 141,563 | | | | 103,740 | | | | 351,300 | | | | 290,507 | |
Purchased Electricity for Resale | | | 39,427 | | | | 26,580 | | | | 87,351 | | | | 63,830 | |
Purchased Electricity from AEP Affiliates | | | 112,060 | | | | 96,451 | | | | 296,559 | | | | 249,755 | |
Other Operation | | | 136,875 | | | | 129,439 | | | | 381,928 | | | | 367,483 | |
Maintenance | | | 52,573 | | | | 58,502 | | | | 156,402 | | | | 146,657 | |
Depreciation and Amortization | | | 31,822 | | | | 35,604 | | | | 95,301 | | | | 145,801 | |
Taxes Other Than Income Taxes | | | 19,992 | | | | 19,704 | | | | 60,236 | | | | 56,936 | |
TOTAL | | | 534,312 | | | | 470,020 | | | | 1,429,077 | | | | 1,320,969 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 86,711 | | | | 89,156 | | | | 271,742 | | | | 217,113 | |
| | | | | | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | | | | | |
Other Income | | | 880 | | | | 1,986 | | | | 4,621 | | | | 4,273 | |
Interest Expense | | | (20,629 | ) | | | (18,312 | ) | | | (56,977 | ) | | | (57,744 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 66,962 | | | | 72,830 | | | | 219,386 | | | | 163,642 | |
| | | | | | | | | | | | | | | | |
Income Tax Expense | | | 21,326 | | | | 23,706 | | | | 68,348 | | | | 55,020 | |
| | | | | | | | | | | | | | | | |
NET INCOME | | | 45,636 | | | | 49,124 | | | | 151,038 | | | | 108,622 | |
| | | | | | | | | | | | | | | | |
Preferred Stock Dividend Requirements | | | 85 | | | | 85 | | | | 255 | | | | 255 | |
| | | | | | | | | | | | | | | | |
EARNINGS APPLICABLE TO COMMON STOCK | | $ | 45,551 | | | $ | 49,039 | | | $ | 150,783 | | | $ | 108,367 | |
| | 2009 | | | 2008 | |
REVENUES | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 421,927 | | | $ | 431,592 | |
Sales to AEP Affiliates | | | 59,986 | | | | 76,512 | |
Other – Affiliated | | | 30,740 | | | | 23,219 | |
Other – Nonaffiliated | | | 54,391 | | | | 5,826 | |
TOTAL | | | 567,044 | | | | 537,149 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 102,960 | | | | 101,241 | |
Purchased Electricity for Resale | | | 38,361 | | | | 21,483 | |
Purchased Electricity from AEP Affiliates | | | 79,978 | | | | 92,641 | |
Other Operation | | | 109,460 | | | | 120,366 | |
Maintenance | | | 46,274 | | | | 51,221 | |
Depreciation and Amortization | | | 32,745 | | | | 31,722 | |
Taxes Other Than Income Taxes | | | 20,696 | | | | 19,902 | |
TOTAL | | | 430,474 | | | | 438,576 | |
| | | | | | | | |
OPERATING INCOME | | | 136,570 | | | | 98,573 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest Income | | | 2,543 | | | | 829 | |
Allowance for Equity Funds Used During Construction | | | 1,555 | | | | 880 | |
Interest Expense | | | (23,531 | ) | | | (19,202 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 117,137 | | | | 81,080 | |
| | | | | | | | |
Income Tax Expense | | | 36,185 | | | | 25,822 | |
| | | | | | | | |
NET INCOME | | | 80,952 | | | | 55,258 | |
| | | | | | | | |
Preferred Stock Dividend Requirements | | | 85 | | | | 85 | |
| | | | | | | | |
EARNINGS ATTRIBUTABLE TO COMMON STOCK | | $ | 80,867 | | | $ | 55,173 | |
The common stock of I&M is wholly-owned by AEP. |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the NineThree Months Ended September 30,March 31, 2009 and 2008 and 2007
(in thousands)
(Unaudited)
| | Common Stock | | | Paid-in Capital | | | Retained Earnings | | | Accumulated Other Comprehensive Income (Loss) | | | Total | |
DECEMBER 31, 2006 | | $ | 56,584 | | | $ | 861,290 | | | $ | 386,616 | | | $ | (15,051 | ) | | $ | 1,289,439 | |
| | | | | | | | | | | | | | | | | | | | |
FIN 48 Adoption, Net of Tax | | | | | | | | | | | 327 | | | | | | | | 327 | |
Common Stock Dividends | | | | | | | | | | | (30,000 | ) | | | | | | | (30,000 | ) |
Preferred Stock Dividends | | | | | | | | | | | (255 | ) | | | | | | | (255 | ) |
Gain on Reacquired Preferred Stock | | | | | | | 1 | | | | | | | | | | | | 1 | |
TOTAL | | | | | | | | | | | | | | | | | | | 1,259,512 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Loss, Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $941 | | | | | | | | | | | | | | | (1,747 | ) | | | (1,747 | ) |
NET INCOME | | | | | | | | | | | 108,622 | | | | | | | | 108,622 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 106,875 | |
| | | | | | | | | | | | | | | | | | | | |
SEPTEMBER 30, 2007 | | $ | 56,584 | | | $ | 861,291 | | | $ | 465,310 | | | $ | (16,798 | ) | | $ | 1,366,387 | |
| | | | | | | | | | | | | | | | | | | | |
DECEMBER 31, 2007 | | $ | 56,584 | | | $ | 861,291 | | | $ | 483,499 | | | $ | (15,675 | ) | | $ | 1,385,699 | |
| | | | | | | | | | | | | | | | | | | | |
EITF 06-10 Adoption, Net of Tax of $753 | | | | | | | | | | | (1,398 | ) | | | | | | | (1,398 | ) |
Common Stock Dividends | | | | | | | | | | | (56,250 | ) | | | | | | | (56,250 | ) |
Preferred Stock Dividends | | | | | | | | | | | (255 | ) | | | | | | | (255 | ) |
TOTAL | | | | | | | | | | | | | | | | | | | 1,327,796 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $967 | | | | | | | | | | | | | | | 1,795 | | | | 1,795 | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $178 | | | | | | | | | | | | | | | 331 | | | | 331 | |
NET INCOME | | | | | | | | | | | 151,038 | | | | | | | | 151,038 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 153,164 | |
| | | | | | | | | | | | | | | | | | | | |
SEPTEMBER 30, 2008 | | $ | 56,584 | | | $ | 861,291 | | | $ | 576,634 | | | $ | (13,549 | ) | | $ | 1,480,960 | |
| | Common Stock | | | Paid-in Capital | | | Retained Earnings | | | Accumulated Other Comprehensive Income (Loss) | | | Total | |
| | | | | | | | | | | | | | | |
DECEMBER 31, 2007 | | $ | 56,584 | | | $ | 861,291 | | | $ | 483,499 | | | $ | (15,675 | ) | | $ | 1,385,699 | |
| | | | | | | | | | | | | | | | | | | | |
EITF 06-10 Adoption, Net of Tax of $753 | | | | | | | | | | | (1,398 | ) | | | | | | | (1,398 | ) |
Common Stock Dividends | | | | | | | | | | | (18,750 | ) | | | | | | | (18,750 | ) |
Preferred Stock Dividends | | | | | | | | | | | (85 | ) | | | | | | | (85 | ) |
TOTAL | | | | | | | | | | | | | | | | | | | 1,365,466 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $3,208 | | | | | | | | | | | | | | | (5,958 | ) | | | (5,958 | ) |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $59 | | | | | | | | | | | | | | | 110 | | | | 110 | |
NET INCOME | | | | | | | | | | | 55,258 | | | | | | | | 55,258 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 49,410 | |
| | | | | | | | | | | | | | | | | | | | |
MARCH 31, 2008 | | $ | 56,584 | | | $ | 861,291 | | | $ | 518,524 | | | $ | (21,523 | ) | | $ | 1,414,876 | |
| | | | | | | | | | | | | | | | | | | | |
DECEMBER 31, 2008 | | $ | 56,584 | | | $ | 861,291 | | | $ | 538,637 | | | $ | (21,694 | ) | | $ | 1,434,818 | |
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (24,500 | ) | | | | | | | (24,500 | ) |
Preferred Stock Dividends | | | | | | | | | | | (85 | ) | | | | | | | (85 | ) |
Gain on Reacquired Preferred Stock | | | | | | | 1 | | | | | | | | | | | | 1 | |
TOTAL | | | | | | | | | | | | | | | | | | | 1,410,234 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $463 | | | | | | | | | | | | | | | 859 | | | | 859 | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $111 | | | | | | | | | | | | | | | 207 | | | | 207 | |
NET INCOME | | | | | | | | | | | 80,952 | | | | | | | | 80,952 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 82,018 | |
| | | | | | | | | | | | | | | | | | | | |
MARCH 31, 2009 | | $ | 56,584 | | | $ | 861,292 | | | $ | 595,004 | | | $ | (20,628 | ) | | $ | 1,492,252 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2008March 31, 2009 and December 31, 20072008
(in thousands)
(Unaudited)
| | 2008 | | | 2007 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 1,328 | | | $ | 1,139 | |
Accounts Receivable: | | | | | | | | |
Customers | | | 82,788 | | | | 70,995 | |
Affiliated Companies | | | 77,640 | | | | 92,018 | |
Accrued Unbilled Revenues | | | 21,028 | | | | 16,207 | |
Miscellaneous | | | 2,010 | | | | 1,335 | |
Allowance for Uncollectible Accounts | | | (3,200 | ) | | | (2,711 | ) |
Total Accounts Receivable | | | 180,266 | | | | 177,844 | |
Fuel | | | 46,745 | | | | 61,342 | |
Materials and Supplies | | | 143,245 | | | | 141,384 | |
Risk Management Assets | | | 40,215 | | | | 32,365 | |
Accrued Tax Benefits | | | 1,004 | | | | 4,438 | |
Prepayments and Other | | | 35,829 | | | | 11,091 | |
TOTAL | | | 448,632 | | | | 429,603 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Production | | | 3,512,424 | | | | 3,529,524 | |
Transmission | | | 1,100,255 | | | | 1,078,575 | |
Distribution | | | 1,262,017 | | | | 1,196,397 | |
Other (including nuclear fuel and coal mining) | | | 655,257 | | | | 626,390 | |
Construction Work in Progress | | | 173,062 | | | | 122,296 | |
Total | | | 6,703,015 | | | | 6,553,182 | |
Accumulated Depreciation, Depletion and Amortization | | | 3,000,898 | | | | 2,998,416 | |
TOTAL - NET | | | 3,702,117 | | | | 3,554,766 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 251,451 | | | | 246,435 | |
Spent Nuclear Fuel and Decommissioning Trusts | | | 1,291,986 | | | | 1,346,798 | |
Long-term Risk Management Assets | | | 29,518 | | | | 40,227 | |
Deferred Charges and Other | | | 118,574 | | | | 128,623 | |
TOTAL | | | 1,691,529 | | | | 1,762,083 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 5,842,278 | | | $ | 5,746,452 | |
| | 2009 | | | 2008 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 983 | | | $ | 728 | |
Accounts Receivable: | | | | | | | | |
Customers | | | 53,502 | | | | 70,432 | |
Affiliated Companies | | | 76,951 | | | | 94,205 | |
Accrued Unbilled Revenues | | | 17,943 | | | | 19,260 | |
Miscellaneous | | | 2,100 | | | | 1,010 | |
Allowance for Uncollectible Accounts | | | (3,398 | ) | | | (3,310 | ) |
Total Accounts Receivable | | | 147,098 | | | | 181,597 | |
Fuel | | | 67,036 | | | | 67,138 | |
Materials and Supplies | | | 152,782 | | | | 150,644 | |
Risk Management Assets | | | 38,758 | | | | 35,012 | |
Regulatory Asset for Under-Recovered Fuel Costs | | | 37,649 | | | | 33,066 | |
Prepayments and Other | | | 85,958 | | | | 66,733 | |
TOTAL | | | 530,264 | | | | 534,918 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Production | | | 3,553,486 | | | | 3,534,188 | |
Transmission | | | 1,123,849 | | | | 1,115,762 | |
Distribution | | | 1,320,568 | | | | 1,297,482 | |
Other (including nuclear fuel and coal mining) | | | 746,035 | | | | 703,287 | |
Construction Work in Progress | | | 255,864 | | | | 249,020 | |
Total | | | 6,999,802 | | | | 6,899,739 | |
Accumulated Depreciation, Depletion and Amortization | | | 3,043,645 | | | | 3,019,206 | |
TOTAL - NET | | | 3,956,157 | | | | 3,880,533 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 477,402 | | | | 455,132 | |
Spent Nuclear Fuel and Decommissioning Trusts | | | 1,206,544 | | | | 1,259,533 | |
Long-term Risk Management Assets | | | 33,282 | | | | 27,616 | |
Deferred Charges and Other | | | 108,722 | | | | 86,193 | |
TOTAL | | | 1,825,950 | | | | 1,828,474 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 6,312,371 | | | $ | 6,243,925 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2008March 31, 2009 and December 31, 20072008
(Unaudited)
| | 2008 | | | 2007 | |
CURRENT LIABILITIES | | (in thousands) | |
Advances from Affiliates | | $ | 224,071 | | | $ | 45,064 | |
Accounts Payable: | | | | | | | | |
General | | | 177,480 | | | | 184,435 | |
Affiliated Companies | | | 64,970 | | | | 61,749 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 50,000 | | | | 145,000 | |
Risk Management Liabilities | | | 36,802 | | | | 27,271 | |
Customer Deposits | | | 26,957 | | | | 26,445 | |
Accrued Taxes | | | 60,111 | | | | 60,995 | |
Obligations Under Capital Leases | | | 43,626 | | | | 43,382 | |
Other | | | 133,267 | | | | 130,232 | |
TOTAL | | | 817,284 | | | | 724,573 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 1,377,115 | | | | 1,422,427 | |
Long-term Risk Management Liabilities | | | 17,585 | | | | 26,348 | |
Deferred Income Taxes | | | 382,374 | | | | 321,716 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 693,981 | | | | 789,346 | |
Asset Retirement Obligations | | | 886,278 | | | | 852,646 | |
Deferred Credits and Other | | | 178,621 | | | | 215,617 | |
TOTAL | | | 3,535,954 | | | | 3,628,100 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 4,353,238 | | | | 4,352,673 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 8,080 | | | | 8,080 | |
| | | | | | | | |
Commitments and Contingencies (Note 4) | | | | | | | | |
| | | | | | | | |
COMMON SHAREHOLDER’S EQUITY | | | | | | | | |
Common Stock – No Par Value: | | | | | | | | |
Authorized – 2,500,000 Shares | | | | | | | | |
Outstanding – 1,400,000 Shares | | | 56,584 | | | | 56,584 | |
Paid-in Capital | | | 861,291 | | | | 861,291 | |
Retained Earnings | | | 576,634 | | | | 483,499 | |
Accumulated Other Comprehensive Income (Loss) | | | (13,549 | ) | | | (15,675 | ) |
TOTAL | | | 1,480,960 | | | | 1,385,699 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 5,842,278 | | | $ | 5,746,452 | |
| | 2009 | | | 2008 | |
CURRENT LIABILITIES | | (in thousands) | |
Advances from Affiliates | | $ | 16,421 | | | $ | 476,036 | |
Accounts Payable: | | | | | | | | |
General | | | 149,538 | | | | 194,211 | |
Affiliated Companies | | | 52,450 | | | | 117,589 | |
Long-term Debt Due Within One Year – Affiliated | | | 25,000 | | | | - | |
Risk Management Liabilities | | | 20,101 | | | | 16,079 | |
Customer Deposits | | | 28,161 | | | | 26,809 | |
Accrued Taxes | | | 82,522 | | | | 66,363 | |
Obligations Under Capital Leases | | | 26,410 | | | | 43,512 | |
Other | | | 110,942 | | | | 141,160 | |
TOTAL | | | 511,545 | | | | 1,081,759 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 1,949,877 | | | | 1,377,914 | |
Long-term Risk Management Liabilities | | | 15,440 | | | | 14,311 | |
Deferred Income Taxes | | | 480,091 | | | | 412,264 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 587,787 | | | | 656,396 | |
Asset Retirement Obligations | | | 914,806 | | | | 902,920 | |
Deferred Credits and Other | | | 352,496 | | | | 355,463 | |
TOTAL | | | 4,300,497 | | | | 3,719,268 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 4,812,042 | | | | 4,801,027 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 8,077 | | | | 8,080 | |
| | | | | | | | |
Commitments and Contingencies (Note 4) | | | | | | | | |
| | | | | | | | |
COMMON SHAREHOLDER’S EQUITY | | | | | | | | |
Common Stock – No Par Value: | | | | | | | | |
Authorized – 2,500,000 Shares | | | | | | | | |
Outstanding – 1,400,000 Shares | | | 56,584 | | | | 56,584 | |
Paid-in Capital | | | 861,292 | | | | 861,291 | |
Retained Earnings | | | 595,004 | | | | 538,637 | |
Accumulated Other Comprehensive Income (Loss) | | | (20,628 | ) | | | (21,694 | ) |
TOTAL | | | 1,492,252 | | | | 1,434,818 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 6,312,371 | | | $ | 6,243,925 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the NineThree Months Ended September 30,March 31, 2009 and 2008 and 2007
(in thousands)
(Unaudited)
| | 2009 | | | 2008 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 80,952 | | | $ | 55,258 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 32,745 | | | | 31,722 | |
Deferred Income Taxes | | | 56,889 | | | | 5,191 | |
Deferral of Incremental Nuclear Refueling Outage Expenses, Net | | | (7,851 | ) | | | (881 | ) |
Allowance for Equity Funds Used During Construction | | | (1,555 | ) | | | (880 | ) |
Mark-to-Market of Risk Management Contracts | | | (3,272 | ) | | | (1,308 | ) |
Amortization of Nuclear Fuel | | | 13,228 | | | | 21,619 | |
Change in Other Noncurrent Assets | | | (12,585 | ) | | | (10,754 | ) |
Change in Other Noncurrent Liabilities | | | 9,715 | | | | 14,234 | |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 34,499 | | | | 27,467 | |
Fuel, Materials and Supplies | | | (2,036 | ) | | | 10,107 | |
Accounts Payable | | | (68,603 | ) | | | 408 | |
Accrued Taxes, Net | | | (1,224 | ) | | | 40,026 | |
Other Current Assets | | | (23,110 | ) | | | (6,718 | ) |
Other Current Liabilities | | | (27,859 | ) | | | (21,534 | ) |
Net Cash Flows from Operating Activities | | | 79,933 | | | | 163,957 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (92,814 | ) | | | (67,945 | ) |
Purchases of Investment Securities | | | (178,407 | ) | | | (132,311 | ) |
Sales of Investment Securities | | | 158,086 | | | | 113,951 | |
Acquisitions of Nuclear Fuel | | | (75,670 | ) | | | (98,385 | ) |
Proceeds from Sales of Assets and Other | | | 10,757 | | | | 2,815 | |
Net Cash Flows Used for Investing Activities | | | (178,048 | ) | | | (181,875 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Long-term Debt – Nonaffiliated | | | 567,949 | | | | - | |
Issuance of Long-term Debt – Affiliated | | | 25,000 | | | | - | |
Change in Advances from Affiliates, Net | | | (459,615 | ) | | | 140,874 | |
Retirement of Long-term Debt – Nonaffiliated | | | - | | | | (95,000 | ) |
Retirement of Cumulative Preferred Stock | | | (2 | ) | | | - | |
Principal Payments for Capital Lease Obligations | | | (10,377 | ) | | | (8,529 | ) |
Dividends Paid on Common Stock | | | (24,500 | ) | | | (18,750 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (85 | ) | | | (85 | ) |
Net Cash Flows from Financing Activities | | | 98,370 | | | | 18,510 | |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 255 | | | | 592 | |
Cash and Cash Equivalents at Beginning of Period | | | 728 | | | | 1,139 | |
Cash and Cash Equivalents at End of Period | | $ | 983 | | | $ | 1,731 | |
| | 2008 | | | 2007 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 151,038 | | | $ | 108,622 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 95,301 | | | | 145,801 | |
Deferred Income Taxes | | | 47,565 | | | | (9,235 | ) |
Amortization of Incremental Nuclear Refueling Outage Expenses, Net | | | 834 | | | | 14,450 | |
Allowance for Equity Funds Used During Construction | | | (967 | ) | | | (2,726 | ) |
Mark-to-Market of Risk Management Contracts | | | 4,876 | | | | 3,046 | |
Amortization of Nuclear Fuel | | | 72,453 | | | | 48,360 | |
Change in Other Noncurrent Assets | | | 5,678 | | | | 17,163 | |
Change in Other Noncurrent Liabilities | | | 38,568 | | | | 33,995 | |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | (2,422 | ) | | | 34,569 | |
Fuel, Materials and Supplies | | | 12,736 | | | | 14,584 | |
Accounts Payable | | | 16,549 | | | | (27,015 | ) |
Accrued Taxes, Net | | | 2,550 | | | | 41,243 | |
Other Current Assets | | | (24,736 | ) | | | (4,595 | ) |
Other Current Liabilities | | | 1,393 | | | | 3,150 | |
Net Cash Flows from Operating Activities | | | 421,416 | | | | 421,412 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (221,538 | ) | | | (191,110 | ) |
Purchases of Investment Securities | | | (413,538 | ) | | | (561,509 | ) |
Sales of Investment Securities | | | 362,773 | | | | 505,620 | |
Acquisitions of Nuclear Fuel | | | (99,110 | ) | | | (73,112 | ) |
Proceeds from Sales of Assets and Other | | | 3,376 | | | | 670 | |
Net Cash Flows Used for Investing Activities | | | (368,037 | ) | | | (319,441 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Long-term Debt – Nonaffiliated | | | 115,225 | | | | - | |
Change in Advances from Affiliates, Net | | | 179,007 | | | | (66,939 | ) |
Retirement of Long-term Debt – Nonaffiliated | | | (262,000 | ) | | | - | |
Retirement of Cumulative Preferred Stock | | | - | | | | (2 | ) |
Principal Payments for Capital Lease Obligations | | | (28,917 | ) | | | (3,954 | ) |
Dividends Paid on Common Stock | | | (56,250 | ) | | | (30,000 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (255 | ) | | | (255 | ) |
Net Cash Flows Used for Financing Activities | | | (53,190 | ) | | | (101,150 | ) |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 189 | | | | 821 | |
Cash and Cash Equivalents at Beginning of Period | | | 1,139 | | | | 1,369 | |
Cash and Cash Equivalents at End of Period | | $ | 1,328 | | | $ | 2,190 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 57,086 | | | $ | 49,628 | |
Net Cash Paid for Income Taxes | | | 7,482 | | | | 14,395 | |
Noncash Acquisitions Under Capital Leases | | | 3,279 | | | | 5,847 | |
Construction Expenditures Included in Accounts Payable at September 30, | | | 26,150 | | | | 23,935 | |
Acquisition of Nuclear Fuel Included in Accounts Payable at September 30, | | | 66,127 | | | | 691 | |
SUPPLEMENTARY INFORMATION | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 35,231 | | | $ | 20,216 | |
Net Cash Received for Income Taxes | | | (355 | ) | | | (1,118 | ) |
Noncash Acquisitions Under Capital Leases | | | 705 | | | | 2,023 | |
Construction Expenditures Included in Accounts Payable at March 31, | | | 29,910 | | | | 16,280 | |
Acquisition of Nuclear Fuel Included in Accounts Payable at March 31, | | | 17,016 | | | | - | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The condensed notes to I&M’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to I&M.
| Footnote Reference |
| |
Significant Accounting Matters | Note 1 |
New Accounting Pronouncements and Extraordinary Item | Note 2 |
Rate Matters | Note 3 |
Commitments, Guarantees and Contingencies | Note 4 |
Benefit Plans | Note 65 |
Business Segments | Note 6 |
Derivatives, Hedging and Fair Value Measurements | Note 7 |
Income Taxes | Note 8 |
Financing Activities | Note 9 |
OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
ThirdFirst Quarter of 20082009 Compared to ThirdFirst Quarter of 20072008
Reconciliation of ThirdFirst Quarter of 20072008 to ThirdFirst Quarter of 20082009
Net Income
(in millions)
Third Quarter of 2007 | | | | | $ | 75 | |
| | | | | | | |
Changes in Gross Margin: | | | | | | | |
Retail Margins | | | (48 | ) | | | | |
Off-system Sales | | | 11 | | | | | |
Other | | | 3 | | | | | |
Total Change in Gross Margin | | | | | | | (34 | ) |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | (2 | ) | | | | |
Depreciation and Amortization | | | 12 | | | | | |
Taxes Other Than Income Taxes | | | (1 | ) | | | | |
Other Income | | | 2 | | | | | |
Interest Expense | | | (4 | ) | | | | |
Total Change in Operating Expenses and Other | | | | | | | 7 | |
| | | | | | | | |
Income Tax Expense | | | | | | | 8 | |
| | | | | | | | |
Third Quarter of 2008 | | | | | | $ | 56 | |
First Quarter of 2008 | | | | | $ | 138 | |
| | | | | | | |
Changes in Gross Margin: | | | | | | | |
Retail Margins | | | (37 | ) | | | | |
Off-system Sales | | | (29 | ) | | | | |
Other | | | 10 | | | | | |
Total Change in Gross Margin | | | | | | | (56 | ) |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | (21 | ) | | | | |
Depreciation and Amortization | | | (15 | ) | | | | |
Carrying Costs Income | | | (2 | ) | | | | |
Other Income | | | (2 | ) | | | | |
Interest Expense | | | (5 | ) | | | | |
Total Change in Operating Expenses and Other | | | | | | | (45 | ) |
| | | | | | | | |
Income Tax Expense | | | | | | | 36 | |
| | | | | | | | |
First Quarter of 2009 | | | | | | $ | 73 | |
Net Income decreased $19$65 million to $56$73 million in 2008.2009. The key drivers of the decrease were a $34$56 million decrease in Gross Margin partiallyand a $45 million increase in Operating Expenses and Other offset by an $8a $36 million decrease in Income Tax Expense and a $7 million decrease in Operating Expenses and Other.Expense.
The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:
· | Retail Margins decreased $48$37 million primarily due to the following: |
| · | A $57$58 million decrease in fuel expense related to increased fuel and consumables expenses. CSPCo anda coal contract amendment recorded in 2008 which reduced future deliveries to OPCo have appliedin exchange for an active fuel clause in their Ohio ESP to be effective January 1, 2009.consideration received. |
| · | An $8A $6 million decrease in residential revenue primarily due to an 18% decrease in cooling degree daysretail and the outages causedwholesale sales driven by the remnants of Hurricane Ike.lower industrial usage. |
| These decreases were partially offset by: |
| · | A $17$1 million increase in fuel margins due to the deferral of fuel costs in 2009. The PUCO’s March 2009 approval of OPCo’s ESP allows for the recovery of fuel and related to a net increase in rates implemented.costs beginning January 1, 2009. See “Ohio Electric Security Plan Filings” section of Note 3. |
| · | A $10$9 million increase in capacity settlements under the Interconnection AgreementAgreement. |
| · | An $8 million increase related to an increase in an affiliate’s peak.new rates implemented due to the accrual for March unbilled revenues at higher rates set by the Ohio ESP. |
· | Margins from Off-system Sales increased $11decreased $29 million primarily due to increasedlower physical sales volumes and lower margins driven by higheras a result of lower market prices, partially offset by lowerhigher trading margins. |
· | Other revenues increased $3$10 million primarily due to increased gains on sales of emission allowances. Due to the implementation of OPCo’s ESP as discussed above, emission gains and losses incurred after January 1, 2009 will be included in OPCo’s fuel adjustment clause. |
Operating Expenses and Other and Income Tax Expense changed between years as follows:
· | Other Operation and Maintenance expenses increased $2$21 million primarily due to: |
| · | A $6An $8 million increase related to an obligation to contribute to the “Partnership with Ohio” fund for low income, at-risk customers ordered by the PUCO’s March 2009 approval of OPCo’s ESP. See “Ohio Electric Security Plan Filings” section of Note 3. |
| · | An $8 million increase in recoverable PJM expenses. |
| · | A $4$7 million increase in employee-related expenses.maintenance of overhead lines primarily due to ice and wind storm costs incurred in January and February 2009. |
| · | A $4 million increase in recoverable customer account expenses related to the Universal Service Fund for customers who qualify for payment assistance. |
| · | A $3 million increase in operation and maintenance expenses related to service restoration expenses from the remnants of Hurricane Ike. |
| · | A $2 million increase in plant maintenance expenses. |
| These increases were partially offset by a $17 million decrease resulting from a settlement agreement in the third quarter 2007 related to alleged violations of the NSR provisions of the CAA. The $17 million represents OPCo’s allocation of the settlement. |
· | Depreciation and Amortization expense decreased $12 million primarily due to an $18 million decrease in amortization as a result of completion of amortization of regulatory assets in December 2007, partially offset by a $5 million increase in depreciation related to environmental improvements placed in service at the Cardinal Plant in 2008 and the Mitchell Plant in July 2007. |
· | Interest Expense increased $4 million primarily due to a decrease in the debt component of AFUDC as a result of Mitchell Plant and Cardinal Plant environmental improvements placed in service and higher interest rates on variable rate debt. |
· | Income Tax Expense decreased $8 million primarily due to a decrease in pretax book income. |
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
Net Income
(in millions)
Nine Months Ended September 30, 2007 | | | | | $ | 229 | |
| | | | | | | |
Changes in Gross Margin: | | | | | | | |
Retail Margins | | | (55 | ) | | | | |
Off-system Sales | | | 34 | | | | | |
Other | | | 12 | | | | | |
Total Change in Gross Margin | | | | | | | (9 | ) |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | 8 | | | | | |
Depreciation and Amortization | | | 42 | | | | | |
Carrying Costs Income | | | 1 | | | | | |
Other Income | | | 6 | | | | | |
Interest Expense | | | (20 | ) | | | | |
Total Change in Operating Expenses and Other | | | | | | | 37 | |
| | | | | | | | |
Income Tax Expense | | | | | | | (10 | ) |
| | | | | | | | |
Nine Months Ended September 30, 2008 | | | | | | $ | 247 | |
Net Income increased $18 million to $247 million in 2008. The key drivers of the increase were a $37 million decrease in Operating Expenses and Other, partially offset by a $10 million increase in Income Tax Expense and a $9 million decrease in Gross Margin.
The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:
· | Retail Margins decreased $55 million primarily due to the following: |
| · | A $105 million decrease related to increased fuel and consumables expenses. CSPCo and OPCo have applied for an active fuel clause in their Ohio ESP to be effective January 1, 2009. |
| · | A $9 million decrease in residential revenues primarily due to a 21% decrease in cooling degree days. |
| These decreases were partially offset by: |
| · | A $42 million increase related to a net increase in rates implemented. |
| · | A $29 million increase related to coal contract amendments in 2008. |
| · | A $17 million increase in capacity settlements under the Interconnection Agreement related to an increase in an affiliate’s peak. |
· | Margins from Off-system Sales increased $34 million primarily due to increased physical sales margins driven by higher prices and higher trading margins. |
· | Other revenues increased $12 million primarily due to increased gains on sales of emission allowances. |
Operating Expenses and Other and Income Tax Expense changed between years as follows:
· | Other Operation and Maintenance expenses decreased $8 million primarily due to: |
| · | A $20 million decrease in removal expenses related to planned outages at the Gavin and Mitchell Plants during 2007. |
| · | A $17 million decrease resulting from a settlement agreement in the third quarter 2007 related to alleged violations of the NSR provisions of the CAA. The $17 million represents OPCo’s allocation of the settlement. |
| · | A $7 million decrease in overhead line maintenance expenses. |
| These decreases were partially offset by: |
| · | A $13 million increase in recoverable PJM expenses. |
| · | An $11 million increase in recoverable customer account expenses related to the Universal Service Fund for customers who qualify for payment assistance. |
| · | A $7 million increase in maintenance expenses from planned and forced outages at various plants. |
| These increases were partially offset by: |
| · | A $4$7 million increasedecrease in employee-related expenses. |
· | Depreciation and Amortization decreased $42increased $15 million primarily due to: |
| · | A $53$19 million decrease in amortizationincrease from higher depreciable property balances as a result of environmental improvements placed in service and various other property additions and higher depreciation rates related to shortened depreciable lives for certain generating facilities. |
| · | A $2 million increase as a result of the completion of the amortization of a regulated liability in December 2008 related to energy sales to Ormet at below market rates. See “Ormet” section of Note 3. |
| These increases were partially offset by: |
| · | A $7 million decrease due to the completion of the amortization of regulatory assets in December 2007. |
| · | A $6 million decrease due to the amortization of IGCC pre-construction costs, which ended in the second quarter of 2007. The amortization of IGCC pre-construction costs was offset by a corresponding increase in Retail Margins in 2007. |
| These decreases were partially offset by a $19 million increase in depreciation related to environmental improvements placed in service at the Cardinal Plant in 2008 and the Mitchell Plant in 2007. |
· | Interest Expense increased $20 million primarily due to a decrease in the debt component of AFUDC as a result of Mitchell Plant and Cardinal Plant environmental improvements placed in service, the issuance of additional long-term debt and higher interest rates on variable rate debt.2008. |
· | Income Tax Expense increased $10decreased $36 million primarily due to an increasea decrease in pretax book income. |
Financial Condition
Credit Ratings
S&P and Fitch currently have OPCo on stable outlook, while Moody’s placed OPCo on negative outlook in the first quarterOPCo’s credit ratings as of 2008. Current ratings areMarch 31, 2009 were as follows:
| Moody’s | | S&P | | Fitch |
| | | | | |
Senior Unsecured Debt | A3 | | BBB | | BBB+ |
IfS&P and Fitch have OPCo receives an upgrade from any of the rating agencies listed above, its borrowing costs could decrease.on stable outlook while Moody’s has OPCo on negative outlook. In January 2009, Moody’s placed OPCo on review for possible downgrade due to concerns about financial metrics and pending cost and construction recoveries. If OPCo receives a downgrade from any of the rating agencies, listed above, its borrowing costs could increase and access to borrowed funds could be negatively affected.
Cash Flow
Cash flows for the ninethree months ended September 30,March 31, 2009 and 2008 and 2007 were as follows:
| | 2008 | | | 2007 | |
| | (in thousands) | |
Cash and Cash Equivalents at Beginning of Period | | $ | 6,666 | | | $ | 1,625 | |
Cash Flows from (Used for): | | | | | | | | |
Operating Activities | | | 434,295 | | | | 402,980 | |
Investing Activities | | | (486,678 | ) | | | (743,260 | ) |
Financing Activities | | | 54,805 | | | | 351,381 | |
Net Increase in Cash and Cash Equivalents | | | 2,422 | | | | 11,101 | |
Cash and Cash Equivalents at End of Period | | $ | 9,088 | | | $ | 12,726 | |
| | 2009 | | | 2008 | |
| | (in thousands) | |
Cash and Cash Equivalents at Beginning of Period | | $ | 12,679 | | | $ | 6,666 | |
Cash Flows from (Used for): | | | | | | | | |
Operating Activities | | | (22,900 | ) | | | 150,065 | |
Investing Activities | | | (156,584 | ) | | | (140,253 | ) |
Financing Activities | | | 180,174 | | | | (12,861 | ) |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 690 | | | | (3,049 | ) |
Cash and Cash Equivalents at End of Period | | $ | 13,369 | | | $ | 3,617 | |
Operating Activities
Net Cash Flows fromUsed for Operating Activities were $434$23 million in 2008.2009. OPCo produced Net Incomeincome of $247$73 million during the period and a noncash expense item of $212$84 million for Depreciation and Amortization.Amortization, $72 million for Deferred Income Taxes and $65 million for Fuel Over/Under-Recovery due to an under-recovery of fuel costs in Ohio. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital and changes in the future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. Accounts Payable had a $45 million inflow primarily due to increases in tonnage and prices per ton related to fuel and consumable purchases. Fuel, Materials and Supplies had a $48 million outflow due to price increases.
Net Cash Flows from Operating Activities were $403 million in 2007. OPCo produced Net Income of $229 million during the period and a noncash expense item of $253 million for Depreciation and Amortization. The other changes in assets and liabilities represent 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. The priorcurrent period activity in working capital included two significantprimarily relates to a number of items. Accounts Payable had a $60$95 million cash outflow partiallyprimarily due to emission allowance paymentsOPCo’s provision for revenue refund of $62 million which was paid in January 2007, reducedthe first quarter 2009 to the AEP West companies as part of the FERC’s recent order on the SIA. Accrued Taxes, Net had a $79 million cash outflow due to a decrease of federal income tax related accruals for Mitchell Plant environmental projects that went into service in 2007 and temporary timing differences of payments for paymentsproperty taxes. Fuel, Materials and Supplies had a $53 million cash outflow primarily due to affiliates.an increase in coal inventory. Accounts Receivable, Net had a $33$40 million cash outflow partiallyinflow due to timing differences of payments from customers and the timingreceipt of collectionsfinal payment due to a coal contract amendment.
Net Cash Flows from Operating Activities were $150 million in 2008. OPCo produced Net Income of receivables.$138 million during the period and a noncash expense item of $69 million for Depreciation and Amortization. The 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 working capital relates to Accounts Receivable, Net. Accounts Receivable, Net had a $22 million outflow primarily due to a coal contract amendment in January 2008.
Investing Activities
Net Cash Used for Investing Activities were $487$157 million and $743$140 million in 20082009 and 2007,2008, respectively. Construction Expenditures were $453$163 million and $751$142 million in 20082009 and 2007,2008, respectively, primarily related to environmental upgrades, as well as projects to improve service reliability for transmission and distribution. Environmental upgrades include the installation of selective catalytic reduction equipment and the flue gas desulfurization projects at the Cardinal, Amos and Mitchell Plants. In 2007, environmental upgrades were completed for Units 1 and 2 at the Mitchell Plant. For the remainderplants. OPCo forecasts approximately $439 million of 2008, OPCo expects construction expenditures to be approximately $230 million.for all of 2009, excluding AFUDC.
Financing Activities
Net Cash Flows from Financing Activities were $55$180 million in 2008. OPCo issued $165 million of Pollution Control Bonds and $250 million of Senior Unsecured Notes. These increases were partially offset by the retirement of $250 million of Pollution Control Bonds and $13 million of Notes Payable – Nonaffiliated. OPCo also had2009 primarily due to a net decreaseincrease of $186 million in borrowings of $102 million from the Utility Money Pool.
Net Cash Flows fromUsed for Financing Activities were $351$13 million in 2007. OPCo issued $4002008 primarily due to a net decrease of $14 million of Senior Unsecured Notes and $65 million of Pollution Control Bonds. OPCo reducedin borrowings by $96 million from the Utility Money Pool.
Financing Activity
Long-term debt issuances retirements and principal payments made during the first ninethree months of 20082009 were:
Issuances
| | Principal | | Interest | | Due |
Type of Debt | | Amount | | Rate | | Date |
| | (in thousands) | | (%) | | |
Pollution Control Bonds | | $ | 50,000 | | Variable | | 2014 |
Pollution Control Bonds | | | 50,000 | | Variable | | 2014 |
Pollution Control Bonds | | | 65,000 | | Variable | | 2036 |
Senior Unsecured Notes | | | 250,000 | | 5.75 | | 2013 |
None
Retirements and Principal Payments
| | Principal | | Interest | | Due |
Type of Debt | | Amount Paid | | Rate | | Date |
| | (in thousands) | | (%) | | |
Notes Payable – Nonaffiliated | | $ | 1,463 | | 6.81 | | 2008 |
Notes Payable – Nonaffiliated | | | 12,000 | | 6.27 | | 2009 |
Pollution Control Bonds | | | 50,000 | | Variable | | 2014 |
Pollution Control Bonds | | | 50,000 | | Variable | | 2016 |
Pollution Control Bonds | | | 50,000 | | Variable | | 2022 |
Pollution Control Bonds | | | 35,000 | | Variable | | 2022 |
Pollution Control Bonds | | | 65,000 | | Variable | | 2036 |
| | Principal Amount Paid | | Interest | | Due |
Type of Debt | | | Rate | | Date |
| | | (in thousands) | | (%) | | |
Notes Payable – Nonaffiliated | | $ | 3,500 | | 7.21 | | 2009 |
Notes Payable – Nonaffiliated | | | 1,000 | | 6.27 | | 2009 |
Liquidity
In recent months, theThe financial markets have become increasingly unstable and constrainedremain volatile at both a global and domestic level. This systemic marketplace distress is impactingcould impact OPCo’s access to capital, liquidity and cost of capital. The uncertainties in the creditcapital markets could have significant implications on OPCo since it relies on continuing access to capital to fund operations and capital expenditures. Management cannot predict the length of time the credit situation will continue or its impact on OPCo’s operations and ability to issue debt at reasonable interest rates.
OPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity. OPCo has $37 million of Senior Unsecured Notes that will mature in 2008 and $82$78 million of Notes Payable that will mature in 2009. To the extent refinancing is unavailable due to challenging credit markets, OPCo will rely upon cash flows from operations and access to the Utility Money Pool to fund its maturities, current operations and capital expenditures.
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of liquidity.
Summary Obligation Information
A summary of contractual obligations is included in the 20072008 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” and “Financing Activity” above and letters of credit. In April 2008, the Registrant Subsidiaries and certain other companies in the AEP System 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. As of September 30, 2008, $167 million of letters of credit were issued by OPCo under the 3-year credit agreement to support variable rate demand notes.year-end.
Significant Factors
Litigation and Regulatory Activity
In the ordinary course of business, OPCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual outcome of these proceedings 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 which have a probable likelihood of loss and the loss amount can be estimated. For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 20072008 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries”. section. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of relevant factors.
Critical Accounting Estimates
See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 20072008 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.
Adoption of New Accounting Pronouncements
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Market Risks
Risk management assets and liabilities are managed by AEPSC as agent. The related risk management policies and procedures are instituted and administered by AEPSC. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on OPCo.
MTM Risk Management Contract Net Assets
The following two tables summarize the various mark-to-market (MTM) positions included in OPCo’s Condensed Consolidated Balance sheetSheet as of September 30, 2008March 31, 2009 and the reasons for changes in total MTM value as compared to December 31, 2007.2008.
Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of September 30, 2008March 31, 2009
(in thousands)
| | MTM Risk Management Contracts | | | Cash Flow & Fair Value Hedges | | | DETM Assignment (a) | | | Collateral Deposits | | | Total | |
Current Assets | | $ | 77,357 | | | $ | 2,245 | | | $ | - | | | $ | (2,466 | ) | | $ | 77,136 | |
Noncurrent Assets | | | 48,369 | | | | 720 | | | | - | | | | (3,281 | ) | | | 45,808 | |
Total MTM Derivative Contract Assets | | | 125,726 | | | | 2,965 | | | | - | | | | (5,747 | ) | | | 122,944 | |
| | | | | | | | | | | | | | | | | | | | |
Current Liabilities | | | (67,432 | ) | | | (3,170 | ) | | | (2,174 | ) | | | 620 | | | | (72,156 | ) |
Noncurrent Liabilities | | | (24,105 | ) | | | - | | | | (2,222 | ) | | | 36 | | | | (26,291 | ) |
Total MTM Derivative Contract Liabilities | | | (91,537 | ) | | | (3,170 | ) | | | (4,396 | ) | | | 656 | | | | (98,447 | ) |
| | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 34,189 | | | $ | (205 | ) | | $ | (4,396 | ) | | $ | (5,091 | ) | | $ | 24,497 | |
| | MTM Risk Management Contracts | | | Cash Flow Hedge Contracts | | | DETM Assignment (a) | | | Collateral Deposits | | | Total | |
Current Assets | | $ | 65,411 | | | $ | 5,646 | | | $ | - | | | $ | (7,697 | ) | | $ | 63,360 | |
Noncurrent Assets | | | 54,262 | | | | 156 | | | | - | | | | (8,753 | ) | | | 45,665 | |
Total MTM Derivative Contract Assets | | | 119,673 | | | | 5,802 | | | | - | | | | (16,450 | ) | | | 109,025 | |
| | | | | | | | | | | | | | | | | | | | |
Current Liabilities | | | (40,578 | ) | | | (1,268 | ) | | | (1,772 | ) | | | 7,723 | | | | (35,895 | ) |
Noncurrent Liabilities | | | (39,704 | ) | | | (27 | ) | | | (1,203 | ) | | | 15,939 | | | | (24,995 | ) |
Total MTM Derivative Contract Liabilities | | | (80,282 | ) | | | (1,295 | ) | | | (2,975 | ) | | | 23,662 | | | | (60,890 | ) |
| | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 39,391 | | | $ | 4,507 | | | $ | (2,975 | ) | | $ | 7,212 | | | $ | 48,135 | |
(a) | See “Natural Gas Contracts with DETM” section of Note 1615 of the 20072008 Annual Report. |
MTM Risk Management Contract Net Assets
NineThree Months Ended September 30, 2008March 31, 2009
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2007 | | $ | 30,248 | |
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | | | (8,565 | ) |
Fair Value of New Contracts at Inception When Entered During the Period (a) | | | 1,154 | |
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period | | | (64 | ) |
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b) | | | 1,026 | |
Changes in Fair Value Due to Market Fluctuations During the Period (c) | | | 13,061 | |
Changes in Fair Value Allocated to Regulated Jurisdictions (d) | | | (2,671 | ) |
Total MTM Risk Management Contract Net Assets | | | 34,189 | |
Net Cash Flow & Fair Value Hedge Contracts | | | (205 | ) |
DETM Assignment (e) | | | (4,396 | ) |
Collateral Deposits | | | (5,091 | ) |
Ending Net Risk Management Assets at September 30, 2008 | | $ | 24,497 | |
Total MTM Risk Management Contract Net Assets at December 31, 2008 | | $ | 37,761 | |
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | | | (4,634 | ) |
Fair Value of New Contracts at Inception When Entered During the Period (a) | | | 1,153 | |
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period | | | - | |
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts | | | - | |
Changes in Fair Value Due to Market Fluctuations During the Period (b) | | | 4,165 | |
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | | | 946 | |
Total MTM Risk Management Contract Net Assets | | | 39,391 | |
Cash Flow Hedge Contracts | | | 4,507 | |
DETM Assignment (d) | | | (2,975 | ) |
Collateral Deposits | | | 7,212 | |
Ending Net Risk Management Assets at March 31, 2009 | | $ | 48,135 | |
(a) | Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged. |
(b) | Represents the impact of applying AEP’s credit risk when measuring the fair value of derivative liabilities according to SFAS 157. |
(c) | Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc. |
(d)(c) | “Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities.liabilities/assets. |
(e)(d) | See “Natural Gas Contracts with DETM” section of Note 1615 of the 20072008 Annual Report. |
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The following table presents the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash:
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2008March 31, 2009
(in thousands)
| | Remainder | | | | | | | | | | | | | | | After | | | | |
| | 2008 | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | 2012 | | | Total | |
Level 1 (a) | | $ | (695 | ) | | $ | (1,596 | ) | | $ | (15 | ) | | $ | - | | | $ | - | | | $ | - | | | $ | (2,306 | ) |
Level 2 (b) | | | 310 | | | | 16,487 | | | | 12,052 | | | | 724 | | | | 338 | | | | - | | | | 29,911 | |
Level 3 (c) | | | (2,788 | ) | | | 462 | | | | (1,303 | ) | | | 189 | | | | 107 | | | | - | | | | (3,333 | ) |
Total | | | (3,173 | ) | | | 15,353 | | | | 10,734 | | | | 913 | | | | 445 | | | | - | | | | 24,272 | |
Dedesignated Risk Management Contracts (d) | | | 976 | | | | 3,282 | | | | 3,256 | | | | 1,268 | | | | 1,135 | | | | - | | | | 9,917 | |
Total MTM Risk Management Contract Net Assets (Liabilities) | | $ | (2,197 | ) | | $ | 18,635 | | | $ | 13,990 | | | $ | 2,181 | | | $ | 1,580 | | | $ | - | | | $ | 34,189 | |
| | Remainder | | | | | | | | | | | | | | | After | | | | |
| | 2009 | | | 2010 | | | 2011 | | | 2012 | | | 2013 | | | 2013 | | | Total | |
Level 1 (a) | | $ | (1,193 | ) | | $ | (31 | ) | | $ | 1 | | | $ | - | | | $ | - | | | $ | - | | | $ | (1,223 | ) |
Level 2 (b) | | | 15,214 | | | | 6,549 | | | | 3,357 | | | | (342 | ) | | | 26 | | | | - | | | | 24,804 | |
Level 3 (c) | | | 3,633 | | | | 1,826 | | | | 1,103 | | | | 1,096 | | | | 144 | | | | - | | | | 7,802 | |
Total | | | 17,654 | | | | 8,344 | | | | 4,461 | | | | 754 | | | | 170 | | | | - | | | | 31,383 | |
Dedesignated Risk Management Contracts (d) | | | 2,456 | | | | 3,195 | | | | 1,244 | | | | 1,113 | | | | - | | | | - | | | | 8,008 | |
Total MTM Risk Management Contract Net Assets | | $ | 20,110 | | | $ | 11,539 | | | $ | 5,705 | | | $ | 1,867 | | | $ | 170 | | | $ | - | | | $ | 39,391 | |
(a) | Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis. |
(b) | Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1 and OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market. |
(c) | Level 3 inputs are unobservable inputs for the asset or liability. Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions. |
(d) | Dedesignated Risk Management Contracts are contracts that were originally MTM but were subsequently elected as normal under SFAS 133. At the time of the normal election, the MTM value was frozen and no longer fair valued. This will be amortized into Revenues over the remaining life of the contract.contracts. |
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed Consolidated Balance Sheet |
OPCo is exposed to market fluctuations in energy commodity prices impacting power operations. Management monitors these risks on future operations and may use various commodity instruments designated in qualifying cash flow hedge strategies to mitigate the impact of these fluctuations on the future cash flows. Management does not hedge all commodity price risk.
Management uses interest rate derivative transactions to manage interest rate risk related to anticipated borrowings of fixed-rate debt. Management does not hedge all interest rate risk.
Management uses foreign currency derivatives to lock in prices on certain forecasted transactions denominated in foreign currencies where deemed necessary, and designates qualifying instruments as cash flow hedges. Management does not hedge all foreign currency exposure.
The following table provides the detail on designated, effective cash flow hedges included in AOCI on OPCo’s Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 2007 to September 30, 2008. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2008
(in thousands)
| | | | | | | | Foreign | | | | |
| | Power | | | Interest Rate | | | Currency | | | Total | |
Beginning Balance in AOCI December 31, 2007 | | $ | (756 | ) | | $ | 2,167 | | | $ | (254 | ) | | $ | 1,157 | |
Changes in Fair Value | | | 431 | | | | (903 | ) | | | 68 | | | | (404 | ) |
Reclassifications from AOCI for Cash Flow Hedges Settled | | | 859 | | | | 160 | | | | 10 | | | | 1,029 | |
Ending Balance in AOCI September 30, 2008 | | $ | 534 | | | $ | 1,424 | | | $ | (176 | ) | | $ | 1,782 | |
The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is a $328 thousand loss.
Credit Risk
Counterparty credit quality and exposure is generally consistent with that of AEP.
See Note 7 for further information regarding MTM risk management contracts, cash flow hedging, accumulated other comprehensive income, credit risk and collateral triggering events.
VaR Associated with Risk Management Contracts
Management uses a risk measurement model, which calculates Value at Risk (VaR) to measure commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at September 30, 2008,March 31, 2009, a near term typical change in commodity prices is not expected to have a material effect on OPCo’s net income, cash flows or financial condition.
The following table shows the end, high, average, and low market risk as measured by VaR for the periods indicated:
Nine Months Ended | | | | | Twelve Months Ended |
September 30, 2008 | | | | | December 31, 2007 |
(in thousands) | | | | | (in thousands) |
End | | High | | Average | | Low | | | | | End | | High | | Average | | Low |
$901 | | $1,284 | | $447 | | $132 | | | | | $325 | | $2,054 | | $490 | | $90 |
Three Months Ended | | | | | Twelve Months Ended |
March 31, 2009 | | | | | December 31, 2008 |
(in thousands) | | | | | (in thousands) |
End | | High | | Average | | Low | | | | | End | | High | | Average | | Low |
$247 | | $439 | | $238 | | $113 | | | | | $140 | | $1,284 | | $411 | | $131 |
Management back-tests its VaR results against performance due to actual price moves. Based on the assumed 95% confidence interval, performance due to actual price moves would be expected to exceed the VaR at least once every 20 trading days. Management’s backtesting results show that its actual performance exceeded VaR far fewer than once every 20 trading days. As a result, management believes OPCo’s VaR calculation is conservative.
As OPCo’s VaR calculation captures recent price moves, management also performs regular stress testing of the portfolio to understand itsOPCo’s exposure to extreme price moves. Management employs a historically-basedhistorical-based method whereby the current portfolio is subjected to actual, observed price moves from the last three years in order to ascertain which historical price moves translatetranslated into the largest potential mark-to-marketMTM loss. Management then researches the underlying positions, price moves and market events that created the most significant exposure.
Interest Rate Risk
Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which OPCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months. The estimated EaR on OPCo’s debt portfolio was $10.1$12 million.
OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)
| | Three Months Ended | | | Nine Months Ended | |
| | 2008 | | | 2007 | | | 2008 | | | 2007 | |
REVENUES | | | | | | | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 600,841 | | | $ | 543,404 | | | $ | 1,672,203 | | | $ | 1,516,383 | |
Sales to AEP Affiliates | | | 245,830 | | | | 205,193 | | | | 739,077 | | | | 564,292 | |
Other - Affiliated | | | 5,759 | | | | 5,749 | | | | 17,545 | | | | 16,604 | |
Other - Nonaffiliated | | | 4,584 | | | | 3,397 | | | | 12,738 | | | | 10,838 | |
TOTAL | | | 857,014 | | | | 757,743 | | | | 2,441,563 | | | | 2,108,117 | |
| | | | | | | | | | | | | | | | |
EXPENSES | | | | | | | | | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 359,341 | | | | 254,310 | | | | 928,465 | | | | 653,941 | |
Purchased Electricity for Resale | | | 56,142 | | | | 33,178 | | | | 129,874 | | | | 85,900 | |
Purchased Electricity from AEP Affiliates | | | 48,867 | | | | 43,147 | | | | 116,540 | | | | 92,858 | |
Other Operation | | | 98,653 | | | | 102,850 | | | | 280,494 | | | | 292,809 | |
Maintenance | | | 51,791 | | | | 45,663 | | | | 159,706 | | | | 155,428 | |
Depreciation and Amortization | | | 72,180 | | | | 84,400 | | | | 211,919 | | | | 253,455 | |
Taxes Other Than Income Taxes | | | 49,019 | | | | 47,506 | | | | 146,534 | | | | 146,211 | |
TOTAL | | | 735,993 | | | | 611,054 | | | | 1,973,532 | | | | 1,680,602 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 121,021 | | | | 146,689 | | | | 468,031 | | | | 427,515 | |
| | | | | | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | | | | | |
Interest Income | | | 2,252 | | | | 108 | | | | 6,910 | | | | 992 | |
Carrying Costs Income | | | 3,936 | | | | 3,644 | | | | 12,159 | | | | 10,779 | |
Allowance for Equity Funds Used During Construction | | | 555 | | | | 590 | | | | 1,801 | | | | 1,607 | |
Interest Expense | | | (39,964 | ) | | | (36,262 | ) | | | (116,199 | ) | | | (95,927 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 87,800 | | | | 114,769 | | | | 372,702 | | | | 344,966 | |
| | | | | | | | | | | | | | | | |
Income Tax Expense | | | 31,601 | | | | 39,507 | | | | 125,782 | | | | 116,103 | |
| | | | | | | | | | | | | | | | |
NET INCOME | | | 56,199 | | | | 75,262 | | | | 246,920 | | | | 228,863 | |
| | | | | | | | | | | | | | | | |
Preferred Stock Dividend Requirements | | | 183 | | | | 183 | | | | 549 | | | | 549 | |
| | | | | | | | | | | | | | | | |
EARNINGS APPLICABLE TO COMMON STOCK | | $ | 56,016 | | | $ | 75,079 | | | $ | 246,371 | | | $ | 228,314 | |
The common stock of OPCo is wholly-owned by AEP. |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)
| | Common Stock | | | Paid-in Capital | | | Retained Earnings | | | Accumulated Other Comprehensive Income (Loss) | | | Total | |
DECEMBER 31, 2006 | | $ | 321,201 | | | $ | 536,639 | | | $ | 1,207,265 | | | $ | (56,763 | ) | | $ | 2,008,342 | |
| | | | | | | | | | | | | | | | | | | | |
FIN 48 Adoption, Net of Tax | | | | | | | | | | | (5,380 | ) | | | | | | | (5,380 | ) |
Preferred Stock Dividends | | | | | | | | | | | (549 | ) | | | | | | | (549 | ) |
TOTAL | | | | | | | | | | | | | | | | | | | 2,002,413 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Loss, Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $1,878 | | | | | | | | | | | | | | | (3,486 | ) | | | (3,486 | ) |
NET INCOME | | | | | | | | | | | 228,863 | | | | | | | | 228,863 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 225,377 | |
| | | | | | | | | | | | | | | | | | | | |
SEPTEMBER 30, 2007 | | $ | 321,201 | | | $ | 536,639 | | | $ | 1,430,199 | | | $ | (60,249 | ) | | $ | 2,227,790 | |
| | | | | | | | | | | | | | | | | | | | |
DECEMBER 31, 2007 | | $ | 321,201 | | | $ | 536,640 | | | $ | 1,469,717 | | | $ | (36,541 | ) | | $ | 2,291,017 | |
| | | | | | | | | | | | | | | | | | | | |
EITF 06-10 Adoption, Net of Tax of $1,004 | | | | | | | | | | | (1,864 | ) | | | | | | | (1,864 | ) |
SFAS 157 Adoption, Net of Tax of $152 | | | | | | | | | | | (282 | ) | | | | | | | (282 | ) |
Preferred Stock Dividends | | | | | | | | | | | (549 | ) | | | | | | | (549 | ) |
TOTAL | | | | | | | | | | | | | | | | | | | 2,288,322 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $337 | | | | | | | | | | | | | | | 625 | | | | 625 | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $1,136 | | | | | | | | | | | | | | | 2,110 | | | | 2,110 | |
NET INCOME | | | | | | | | | | | 246,920 | | | | | | | | 246,920 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 249,655 | |
| | | | | | | | | | | | | | | | | | | | |
SEPTEMBER 30, 2008 | | $ | 321,201 | | | $ | 536,640 | | | $ | 1,713,942 | | | $ | (33,806 | ) | | $ | 2,537,977 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2008 and December 31, 2007
(in thousands)
(Unaudited)
| | 2008 | | | 2007 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 9,088 | | | $ | 6,666 | |
Advances to Affiliates | | | 39,758 | | | | - | |
Accounts Receivable: | | | | | | | | |
Customers | | | 93,951 | | | | 104,783 | |
Affiliated Companies | | | 105,503 | | | | 119,560 | |
Accrued Unbilled Revenues | | | 24,947 | | | | 26,819 | |
Miscellaneous | | | 11,551 | | | | 1,578 | |
Allowance for Uncollectible Accounts | | | (3,555 | ) | | | (3,396 | ) |
Total Accounts Receivable | | | 232,397 | | | | 249,344 | |
Fuel | | | 146,332 | | | | 92,874 | |
Materials and Supplies | | | 104,924 | | | | 108,447 | |
Risk Management Assets | | | 77,136 | | | | 44,236 | |
Prepayments and Other | | | 38,372 | | | | 18,300 | |
TOTAL | | | 648,007 | | | | 519,867 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Production | | | 5,937,723 | | | | 5,641,537 | |
Transmission | | | 1,101,463 | | | | 1,068,387 | |
Distribution | | | 1,442,047 | | | | 1,394,988 | |
Other | | | 379,242 | | | | 318,805 | |
Construction Work in Progress | | | 683,404 | | | | 716,640 | |
Total | | | 9,543,879 | | | | 9,140,357 | |
Accumulated Depreciation and Amortization | | | 3,084,683 | | | | 2,967,285 | |
TOTAL - NET | | | 6,459,196 | | | | 6,173,072 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 324,260 | | | | 323,105 | |
Long-term Risk Management Assets | | | 45,808 | | | | 49,586 | |
Deferred Charges and Other | | | 207,562 | | | | 272,799 | |
TOTAL | | | 577,630 | | | | 645,490 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 7,684,833 | | | $ | 7,338,429 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2008 and December 31, 2007
(Unaudited)
| | 2008 | | | 2007 | |
CURRENT LIABILITIES | | (in thousands) | |
Advances from Affiliates | | $ | - | | | $ | 101,548 | |
Accounts Payable: | | | | | | | | |
General | | | 187,803 | | | | 141,196 | |
Affiliated Companies | | | 132,195 | | | | 137,389 | |
Short-term Debt – Nonaffiliated | | | - | | | | 701 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 119,225 | | | | 55,188 | |
Risk Management Liabilities | | | 72,156 | | | | 40,548 | |
Customer Deposits | | | 24,002 | | | | 30,613 | |
Accrued Taxes | | | 130,211 | | | | 185,011 | |
Accrued Interest | | | 37,704 | | | | 41,880 | |
Other | | | 151,044 | | | | 149,658 | |
TOTAL | | | 854,340 | | | | 883,732 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 2,682,247 | | | | 2,594,410 | |
Long-term Debt – Affiliated | | | 200,000 | | | | 200,000 | |
Long-term Risk Management Liabilities | | | 26,291 | | | | 32,194 | |
Deferred Income Taxes | | | 957,441 | | | | 914,170 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 150,794 | | | | 160,721 | |
Deferred Credits and Other | | | 242,084 | | | | 229,635 | |
TOTAL | | | 4,258,857 | | | | 4,131,130 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 5,113,197 | | | | 5,014,862 | |
| | | | | | | | |
Minority Interest | | | 17,032 | | | | 15,923 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 16,627 | | | | 16,627 | |
| | | | | | | | |
Commitments and Contingencies (Note 4) | | | | | | | | |
| | | | | | | | |
COMMON SHAREHOLDER’S EQUITY | | | | | | | | |
Common Stock – No Par Value: | | | | | | | | |
Authorized – 40,000,000 Shares | | | | | | | | |
Outstanding – 27,952,473 Shares | | | 321,201 | | | | 321,201 | |
Paid-in Capital | | | 536,640 | | | | 536,640 | |
Retained Earnings | | | 1,713,942 | | | | 1,469,717 | |
Accumulated Other Comprehensive Income (Loss) | | | (33,806 | ) | | | (36,541 | ) |
TOTAL | | | 2,537,977 | | | | 2,291,017 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 7,684,833 | | | $ | 7,338,429 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWSINCOME
For the NineThree Months Ended September 30,March 31, 2009 and 2008 and 2007
(in thousands)
(Unaudited)
| | 2009 | | | 2008 | |
REVENUES | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 524,686 | | | $ | 555,478 | |
Sales to AEP Affiliates | | | 226,694 | | | | 236,848 | |
Other - Affiliated | | | 7,488 | | | | 5,299 | |
Other - Nonaffiliated | | | 3,847 | | | | 4,563 | |
TOTAL | | | 762,715 | | | | 802,188 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 253,474 | | | | 238,934 | |
Purchased Electricity for Resale | | | 52,269 | | | | 34,577 | |
Purchased Electricity from AEP Affiliates | | | 16,742 | | | | 32,516 | |
Other Operation | | | 99,598 | | | | 89,882 | |
Maintenance | | | 60,040 | | | | 48,697 | |
Depreciation and Amortization | | | 84,023 | | | | 68,566 | |
Taxes Other Than Income Taxes | | | 51,492 | | | | 51,578 | |
TOTAL | | | 617,638 | | | | 564,750 | |
| | | | | | | | |
OPERATING INCOME | | | 145,077 | | | | 237,438 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest Income | | | 244 | | | | 2,908 | |
Carrying Costs Income | | | 1,584 | | | | 4,229 | |
Allowance for Equity Funds Used During Construction | | | 867 | | | | 544 | |
Interest Expense | | | (38,681 | ) | | | (33,919 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 109,091 | | | | 211,200 | |
| | | | | | | | |
Income Tax Expense | | | 36,482 | | | | 72,910 | |
| | | | | | | | |
NET INCOME | | | 72,609 | | | | 138,290 | |
| | | | | | | | |
Less: Net Income Attributable to Noncontrolling Interest | | | 463 | | | | 463 | |
| | | | | | | | |
NET INCOME ATTRIBUTABLE TO OPCo SHAREHOLDERS | | | 72,146 | | | | 137,827 | |
| | | | | | | | |
Less: Preferred Stock Dividend Requirements | | | 183 | | | | 183 | |
| | | | | | | | |
EARNINGS ATTRIBUTABLE TO OPCo COMMON SHAREHOLDER | | $ | 71,963 | | | $ | 137,644 | |
| | 2008 | | | 2007 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 246,920 | | | $ | 228,863 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 211,919 | | | | 253,455 | |
Deferred Income Taxes | | | 45,424 | | | | 3,938 | |
Carrying Costs Income | | | (12,159 | ) | | | (10,779 | ) |
Allowance for Equity Funds Used During Construction | | | (1,801 | ) | | | (1,607 | ) |
Mark-to-Market of Risk Management Contracts | | | (2,028 | ) | | | (3,894 | ) |
Deferred Property Taxes | | | 63,867 | | | | 54,036 | |
Change in Other Noncurrent Assets | | | (52,788 | ) | | | (20,275 | ) |
Change in Other Noncurrent Liabilities | | | 9,300 | | | | 8,026 | |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 16,947 | | | | (32,723 | ) |
Fuel, Materials and Supplies | | | (48,197 | ) | | | (1,245 | ) |
Accounts Payable | | | 45,252 | | | | (59,925 | ) |
Accrued Taxes, Net | | | (56,936 | ) | | | (19,997 | ) |
Other Current Assets | | | (14,333 | ) | | | (11,784 | ) |
Other Current Liabilities | | | (17,092 | ) | | | 16,891 | |
Net Cash Flows from Operating Activities | | | 434,295 | | | | 402,980 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (453,405 | ) | | | (751,161 | ) |
Change in Advances to Affiliates, Net | | | (39,758 | ) | | | - | |
Proceeds from Sales of Assets | | | 6,872 | | | | 7,924 | |
Other | | | (387 | ) | | | (23 | ) |
Net Cash Flows Used for Investing Activities | | | (486,678 | ) | | | (743,260 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Long-term Debt – Nonaffiliated | | | 412,389 | | | | 461,324 | |
Change in Short-term Debt, Net – Nonaffiliated | | | (701 | ) | | | 895 | |
Change in Advances from Affiliates, Net | | | (101,548 | ) | | | (95,940 | ) |
Retirement of Long-term Debt – Nonaffiliated | | | (263,463 | ) | | | (8,927 | ) |
Retirement of Cumulative Preferred Stock | | | - | | | | (2 | ) |
Principal Payments for Capital Lease Obligations | | | (4,636 | ) | | | (5,420 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (549 | ) | | | (549 | ) |
Other | | | 13,313 | | | | - | |
Net Cash Flows from Financing Activities | | | 54,805 | | | | 351,381 | |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 2,422 | | | | 11,101 | |
Cash and Cash Equivalents at Beginning of Period | | | 6,666 | | | | 1,625 | |
Cash and Cash Equivalents at End of Period | | $ | 9,088 | | | $ | 12,726 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 112,321 | | | $ | 85,851 | |
Net Cash Paid for Income Taxes | | | 61,051 | | | | 61,459 | |
Noncash Acquisitions Under Capital Leases | | | 2,018 | | | | 1,620 | |
Noncash Acquisition of Coal Land Rights | | | 41,600 | | | | - | |
Construction Expenditures Included in Accounts Payable at September 30, | | | 25,839 | | | | 42,055 | |
The common stock of OPCo is wholly-owned by AEP. |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2009 and 2008
(in thousands)
(Unaudited)
| | OPCo Common Shareholder | | | | | | | |
| | Common Stock | | | Paid-in Capital | | | Retained Earnings | | | Accumulated Other Comprehensive Income (Loss) | | | Noncontrolling Interest | | | Total | |
| | | | | | | | | | | | | | | | | | |
DECEMBER 31, 2007 | | $ | 321,201 | | | $ | 536,640 | | | $ | 1,469,717 | | | $ | (36,541 | ) | | $ | 15,923 | | | $ | 2,306,940 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
EITF 06-10 Adoption, Net of Tax of $1,004 | | | | | | | | | | | (1,864 | ) | | | | | | | | | | | (1,864 | ) |
SFAS 157 Adoption, Net of Tax of $152 | | | | | | | | | | | (282 | ) | | | | | | | | | | | (282 | ) |
Common Stock Dividends – Nonaffiliated | | | | | | | | | | | | | | | | | | | (463 | ) | | | (463 | ) |
Preferred Stock Dividends | | | | | | | | | | | (183 | ) | | | | | | | | | | | (183 | ) |
Other | | | | | | | | | | | | | | | | | | | 2,015 | | | | 2,015 | |
TOTAL | | | | | | | | | | | | | | | | | | | | | | | 2,306,163 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $4,745 | | | | | | | | | | | | | | | (8,811 | ) | | | | | | | (8,811 | ) |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $379 | | | | | | | | | | | | | | | 703 | | | | | | | | 703 | |
NET INCOME | �� | | | | | | | | | | 137,827 | | | | | | | | 463 | | | | 138,290 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | 130,182 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
MARCH 31, 2008 | | $ | 321,201 | | | $ | 536,640 | | | $ | 1,605,215 | | | $ | (44,649 | ) | | $ | 17,938 | | | $ | 2,436,345 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
DECEMBER 31, 2008 | | $ | 321,201 | | | $ | 536,640 | | | $ | 1,697,962 | | | $ | (133,858 | ) | | $ | 16,799 | | | $ | 2,438,744 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends – Nonaffiliated | | | | | | | | | | | | | | | | | | | (463 | ) | | | (463 | ) |
Preferred Stock Dividends | | | | | | | | | | | (183 | ) | | | | | | | | | | | (183 | ) |
Other | | | | | | | | | | | | | | | | | | | 1,111 | | | | 1,111 | |
TOTAL | | | | | | | | | | | | | | | | | | | | | | | 2,439,209 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $570 | | | | | | | | | | | | | | | 1,058 | | | | | | | | 1,058 | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $855 | | | | | | | | | | | | | | | 1,588 | | | | | | | | 1,588 | |
NET INCOME | | | | | | | | | | | 72,146 | | | | | | | | 463 | | | | 72,609 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | 75,255 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
MARCH 31, 2009 | | $ | 321,201 | | | $ | 536,640 | | | $ | 1,769,925 | | | $ | (131,212 | ) | | $ | 17,910 | | | $ | 2,514,464 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
March 31, 2009 and December 31, 2008
(in thousands)
(Unaudited)
| | 2009 | | | 2008 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 13,369 | | | $ | 12,679 | |
Accounts Receivable: | | | | | | | | |
Customers | | | 76,210 | | | | 91,235 | |
Affiliated Companies | | | 99,508 | | | | 118,721 | |
Accrued Unbilled Revenues | | | 22,658 | | | | 18,239 | |
Miscellaneous | | | 12,797 | | | | 23,393 | |
Allowance for Uncollectible Accounts | | | (3,630 | ) | | | (3,586 | ) |
Total Accounts Receivable | | | 207,543 | | | | 248,002 | |
Fuel | | | 238,012 | | | | 186,904 | |
Materials and Supplies | | | 108,899 | | | | 107,419 | |
Risk Management Assets | | | 63,360 | | | | 53,292 | |
Accrued Tax Benefits | | | 51,287 | | | | 13,568 | |
Prepayments and Other | | | 40,101 | | | | 42,999 | |
TOTAL | | | 722,571 | | | | 664,863 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Production | | | 6,589,421 | | | | 6,025,277 | |
Transmission | | | 1,128,310 | | | | 1,111,637 | |
Distribution | | | 1,493,642 | | | | 1,472,906 | |
Other | | | 390,415 | | | | 391,862 | |
Construction Work in Progress | | | 270,475 | | | | 787,180 | |
Total | | | 9,872,263 | | | | 9,788,862 | |
Accumulated Depreciation and Amortization | | | 3,149,697 | | | | 3,122,989 | |
TOTAL - NET | | | 6,722,566 | | | | 6,665,873 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 510,585 | | | | 449,216 | |
Long-term Risk Management Assets | | | 45,665 | | | | 39,097 | |
Deferred Charges and Other | | | 160,171 | | | | 184,777 | |
TOTAL | | | 716,421 | | | | 673,090 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 8,161,558 | | | $ | 8,003,826 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
March 31, 2009 and December 31, 2008
(Unaudited)
| | 2009 | | | 2008 | |
CURRENT LIABILITIES | | (in thousands) | |
Advances from Affiliates | | $ | 320,166 | | | $ | 133,887 | |
Accounts Payable: | | | | | | | | |
General | | | 188,516 | | | | 193,675 | |
Affiliated Companies | | | 99,427 | | | | 206,984 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 73,000 | | | | 77,500 | |
Risk Management Liabilities | | | 35,895 | | | | 29,218 | |
Customer Deposits | | | 26,406 | | | | 24,333 | |
Accrued Taxes | | | 146,442 | | | | 187,256 | |
Accrued Interest | | | 35,934 | | | | 44,245 | |
Other | | | 166,113 | | | | 163,702 | |
TOTAL | | | 1,091,899 | | | | 1,060,800 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 2,762,039 | | | | 2,761,876 | |
Long-term Debt – Affiliated | | | 200,000 | | | | 200,000 | |
Long-term Risk Management Liabilities | | | 24,995 | | | | 23,817 | |
Deferred Income Taxes | | | 971,014 | | | | 927,072 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 127,916 | | | | 127,788 | |
Employee Benefits and Pension Obligations | | | 284,918 | | | | 288,106 | |
Deferred Credits and Other | | | 167,686 | | | | 158,996 | |
TOTAL | | | 4,538,568 | | | | 4,487,655 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 5,630,467 | | | | 5,548,455 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 16,627 | | | | 16,627 | |
| | | | | | | | |
Commitments and Contingencies (Note 4) | | | | | | | | |
| | | | | | | | |
EQUITY | | | | | | | | |
Common Stock – No Par Value: | | | | | | | | |
Authorized – 40,000,000 Shares | | | | | | | | |
Outstanding – 27,952,473 Shares | | | 321,201 | | | | 321,201 | |
Paid-in Capital | | | 536,640 | | | | 536,640 | |
Retained Earnings | | | 1,769,925 | | | | 1,697,962 | |
Accumulated Other Comprehensive Income (Loss) | | | (131,212 | ) | | | (133,858 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | | 2,496,554 | | | | 2,421,945 | |
| | | | | | | | |
Noncontrolling Interest | | | 17,910 | | | | 16,799 | |
| | | | | | | | |
TOTAL EQUITY | | | 2,514,464 | | | | 2,438,744 | |
| | | | | | | | |
TOTAL LIABILITIES AND EQUITY | | $ | 8,161,558 | | | $ | 8,003,826 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries.
OHIO POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2009 and 2008
(in thousands)
(Unaudited)
| | 2009 | | | 2008 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 72,609 | | | $ | 138,290 | |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 84,023 | | | | 68,566 | |
Deferred Income Taxes | | | 71,740 | | | | 10,850 | |
Carrying Costs Income | | | (1,584 | ) | | | (4,229 | ) |
Allowance for Equity Funds Used During Construction | | | (867 | ) | | | (544 | ) |
Mark-to-Market of Risk Management Contracts | | | (7,117 | ) | | | (5,035 | ) |
Deferred Property Taxes | | | 21,527 | | | | 20,574 | |
Fuel Over/Under-Recovery, Net | | | (65,192 | ) | | | - | |
Change in Other Noncurrent Assets | | | 1,669 | | | | (46,438 | ) |
Change in Other Noncurrent Liabilities | | | 19,318 | | | | 5,397 | |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 39,518 | | | | (21,586 | ) |
Fuel, Materials and Supplies | | | (52,588 | ) | | | (4,130 | ) |
Accounts Payable | | | (95,306 | ) | | | 9,005 | |
Customer Deposits | | | 2,073 | | | | 69 | |
Accrued Taxes, Net | | | (78,533 | ) | | | 15,790 | |
Accrued Interest | | | (8,311 | ) | | | (4,348 | ) |
Other Current Assets | | | (15,394 | ) | | | (13,020 | ) |
Other Current Liabilities | | | (10,485 | ) | | | (19,146 | ) |
Net Cash Flows from (Used for) Operating Activities | | | (22,900 | ) | | | 150,065 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (163,263 | ) | | | (142,257 | ) |
Proceeds from Sales of Assets | | | 2,796 | | | | 2,004 | |
Other | | | 3,883 | | | | - | |
Net Cash Flows Used for Investing Activities | | | (156,584 | ) | | | (140,253 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Change in Short-term Debt, Net – Nonaffiliated | | | - | | | | (701 | ) |
Change in Advances from Affiliates, Net | | | 186,279 | | | | (14,140 | ) |
Retirement of Long-term Debt – Nonaffiliated | | | (4,500 | ) | | | (7,463 | ) |
Funds from Amended Coal Contact | | | - | | | | 10,000 | |
Principal Payments for Capital Lease Obligations | | | (1,316 | ) | | | (1,926 | ) |
Dividends Paid on Common Stock – Nonaffiliated | | | (463 | ) | | | (463 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (183 | ) | | | (183 | ) |
Other | | | 357 | | | | 2,015 | |
Net Cash Flows from (Used for) Financing Activities | | | 180,174 | | | | (12,861 | ) |
| | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 690 | | | | (3,049 | ) |
Cash and Cash Equivalents at Beginning of Period | | | 12,679 | | | | 6,666 | |
Cash and Cash Equivalents at End of Period | | $ | 13,369 | | | $ | 3,617 | |
SUPPLEMENTARY INFORMATION | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 64,554 | | | $ | 37,491 | |
Net Cash Paid for Income Taxes | | | 2,337 | | | | 10,850 | |
Noncash Acquisitions Under Capital Leases | | | 157 | | | | 687 | |
Noncash Acquisition of Coal Land Rights | | | - | | | | 41,600 | |
Construction Expenditures Included in Accounts Payable at March 31, | | | 15,767 | | | | 21,828 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
OHIO POWER COMPANY CONSOLIDATED
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES
The condensed notes to OPCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to OPCo.
| Footnote Reference |
| |
Significant Accounting Matters | Note 1 |
New Accounting Pronouncements and Extraordinary Item | Note 2 |
Rate Matters | Note 3 |
Commitments, Guarantees and Contingencies | Note 4 |
Benefit Plans | Note 65 |
Business Segments | Note 6 |
Derivatives, Hedging and Fair Value Measurements | Note 7 |
Income Taxes | Note 8 |
Financing Activities | Note 9 |
PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
ThirdFirst Quarter of 20082009 Compared to ThirdFirst Quarter of 20072008
Reconciliation of ThirdFirst Quarter of 20072008 to ThirdFirst Quarter of 20082009
Net Income
(in millions)
Third Quarter of 2007 | | | | | $ | 37 | |
| | | | | | | |
Changes in Gross Margin: | | | | | | | |
Retail and Off-system Sales Margins | | | (6 | ) | | | | |
Transmission Revenues | | | 3 | | | | | |
Total Change in Gross Margin | | | | | | | (3 | ) |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | (11 | ) | | | | |
Depreciation and Amortization | | | (3 | ) | | | | |
Taxes Other Than Income Taxes | | | 2 | | | | | |
Other Income | | | (1 | ) | | | | |
Carrying Costs Income | | | 3 | | | | | |
Interest Expense | | | (1 | ) | | | | |
Total Change in Operating Expenses and Other | | | | | | | (11 | ) |
| | | | | | | | |
Income Tax Expense | | | | | | | 5 | |
| | | | | | | | |
Third Quarter of 2008 | | | | | | $ | 28 | |
First Quarter of 2008 | | | | | $ | 37 | |
| | | | | | | |
Changes in Gross Margin: | | | | | | | |
Retail and Off-system Sales Margins | | | 17 | | | | | |
Transmission Revenues | | | 1 | | | | | |
Other | | | (9 | ) | | | | |
Total Change in Gross Margin | | | | | | | 9 | |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | 26 | | | | | |
Deferral of Ice Storm Costs | | | (80 | ) | | | | |
Depreciation and Amortization | | | (2 | ) | | | | |
Other Income | | | (1 | ) | | | | |
Total Change in Operating Expenses and Other | | | | | | | (57 | ) |
| | | | | | | | |
Income Tax Expense | | | | | | | 17 | |
| | | | | | | | |
First Quarter of 2009 | | | | | | $ | 6 | |
Net Income decreased $9$31 million to $28$6 million in 2008.2009. The key drivers of the decrease were an $11a $57 million increase in Operating Expenses and Other, and a $3 million decrease in Gross Margin,partially offset by a $5$17 million decrease in Income Tax Expense.
The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:
· | Retail and Off-system Sales Margins decreased $6 million primarily due to a decrease in retail sales margins mainly due to an 11% decrease in cooling degree days, partially offset by base rate adjustments. |
· | Transmission Revenues increased $3 million primarily due to higher rates within SPP. |
Operating Expenses and Other and Income Tax Expense changed between years as follows:
· | Other Operation and Maintenance expenses increased $11 million primarily due to: |
| · | A $4 million increase primarily associated with outside services and employee-related expenses. |
| · | A $2 million increase in overhead line expenses. |
| · | A $1 million increase in transmission expense primarily due to higher rates within SPP. |
| · | A $1 million increase in expense for the June 2008 storms. |
· | Depreciation and Amortization expenses increased $3 million primarily due to an increase in the amortization of the Lawton Settlement regulatory assets. |
· | Taxes Other Than Income Taxes decreased $2 million primarily due to decreases in real property tax and decreases in state sales and use tax. |
· | Carrying Costs Income increased $3 million primarily due to the new peaking units and to deferred ice storms costs. See “Oklahoma 2007 Ice Storms” section of Note 3. |
· | Income Tax Expense decreased $5 million primarily due to a decrease in pretax book income. |
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
Net Income
(in millions)
Nine Months Ended September 30, 2007 | | | | | $ | 22 | |
| | | | | | | |
Changes in Gross Margin: | | | | | | | |
Retail and Off-system Sales Margins | | | 16 | | | | | |
Transmission Revenues | | | 7 | | | | | |
Other | | | 11 | | | | | |
Total Change in Gross Margin | | | | | | | 34 | |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | (24 | ) | | | | |
Deferral of Ice Storm Costs | | | 72 | | | | | |
Depreciation and Amortization | | | (8 | ) | | | | |
Taxes Other Than Income Taxes | | | 1 | | | | | |
Other Income | | | 2 | | | | | |
Carrying Costs Income | | | 7 | | | | | |
Interest Expense | | | (7 | ) | | | | |
Total Change in Operating Expenses and Other | | | | | | | 43 | |
| | | | | | | | |
Income Tax Expense | | | | | | | (30 | ) |
| | | | | | | | |
Nine Months Ended September 30, 2008 | | | | | | $ | 69 | |
Net Income increased $47 million to $69 million in 2008. The key drivers of the increase were a $43 million decrease in Operating Expenses and Other and a $34$9 million increase in Gross Margin, offset by a $30 million increase in Income Tax Expense.Margin.
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances and purchased power were as follows:
· | Retail and Off-system Sales Margins increased $16$17 million primarily due to an increase in retail sales margins resulting from base rate adjustments during the year, partially offset by a 5% decrease in cooling degree days. |
· | Transmission Revenues increased $7 million primarily due to higher rates within SPP.year. |
· | Other revenues increased $11decreased $9 million primarily due to an increase related to the recognition of the sale of SO2 allowances. See “Oklahoma 2007 Ice Storms” section of Note 3.allowances in 2008. |
Operating Expenses and Other and Income Tax Expense changed between years as follows:
· | Other Operation and Maintenance expenses increased $24decreased $26 million primarily due to: |
| · | A $12$10 million increase in production expensesdecrease primarily due to a $10 million write-off in 2008 of pre-construction costs related to the cancelled Red Rock Generating Facility. |
| · | A $6 million decrease due to the deferral of generation maintenance expenses as a result of PSO’s base rate filing. See “Red Rock Generating Facility”“2008 Oklahoma Base Rate Filing” section of Note 3. |
| · | A $10$4 million increase due todecrease in amortization of the deferred 2007 ice storm costs. |
| · | A $7 million increase in transmission expense primarily due to higher rates within SPP. |
| · | A $6 million increase in administrative and general expenses, primarily associated with outside services and employee-related expenses. |
| · | A $3 million increase in expense for the June 2008 storms. |
| · | A $2 million increase in distribution maintenance expense due to increased vegetation management activities. |
| These increases were partially offset by: |
| · | A $12$4 million decrease for the costs of the January 2007 ice storm. |
| · | A $10 million decrease primarily to true-up actual December ice storm costs to the 2007 estimated accrual.in employee-related expenses. |
· | Deferral of Ice Storm Costs in 2008 of $72$80 million results from an OCC order approving recovery of ice storm costsexpenses related to ice storms in January and December 2007. See “Oklahoma 2007 Ice Storms” section of Note 3. |
· | Depreciation and Amortization expenses increased $8 million primarily due to an increase related to the amortization of the Lawton Settlement regulatory assets. |
· | Other Income increased $2 million primarily due to an increase in the equity componentamortization of AFUDC. |
· | Carrying Costs Income increased $7 million dueregulatory assets related to the new peaking units and deferred ice storm costs.Generation Cost Recovery Rider. See “Oklahoma 2007 Ice Storms”“2008 Oklahoma Base Rate Filing” section of Note 3. |
· | InterestIncome Tax Expense increased $7decreased $17 million primarily due to a $12 million increase in interest expense from long-term borrowings, partially offset by a $4 million decrease in interest expense from short-term borrowings. |
· | Income Tax Expense increased $30 million primarily due to an increase in pretax book income. |
Financial Condition
Credit Ratings
The rating agencies currently have PSO on stable outlook. In the first quarter of 2008, Fitch downgraded PSO from A- to BBB+ for senior unsecured debt. CurrentPSO’s credit ratings areas of March 31, 2009 were as follows:
| Moody’s | | S&P | | Fitch |
| | | | | |
Senior Unsecured Debt | Baa1 | | BBB | | BBB+ |
IfS&P and Fitch have PSO receives an upgrade from any of theon stable outlook. In February 2009, Moody’s affirmed its stable rating agencies listed above, its borrowing costs could decrease.outlook for PSO. If PSO receives a downgrade from any of the rating agencies, listed above, its borrowing costs could increase and access to borrowed funds could be negatively affected.
Cash Flow
Cash flows for the ninethree months ended September 30,March 31, 2009 and 2008 and 2007 were as follows:
| | 2008 | | | 2007 | |
| | (in thousands) | |
Cash and Cash Equivalents at Beginning of Period | | $ | 1,370 | | | $ | 1,651 | |
Cash Flows from (Used for): | | | | | | | | |
Operating Activities | | | 42,386 | | | | 62,042 | |
Investing Activities | | | (161,523 | ) | | | (231,916 | ) |
Financing Activities | | | 120,011 | | | | 169,713 | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 874 | | | | (161 | ) |
Cash and Cash Equivalents at End of Period | | $ | 2,244 | | | $ | 1,490 | |
| | 2009 | | | 2008 | |
| | (in thousands) | |
Cash and Cash Equivalents at Beginning of Period | | $ | 1,345 | | | $ | 1,370 | |
Cash Flows from (Used for): | | | | | | | | |
Operating Activities | | | 103,803 | | | | (39,805 | ) |
Investing Activities | | | (59,145 | ) | | | (21,853 | ) |
Financing Activities | | | (44,726 | ) | | | 61,723 | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | (68 | ) | | | 65 | |
Cash and Cash Equivalents at End of Period | | $ | 1,277 | | | $ | 1,435 | |
Operating Activities
Net Cash Flows from Operating Activities were $42$104 million in 2009. PSO produced Net Income of $6 million during the period and had noncash expense item of $28 million for Depreciation and Amortization offset by a $28 million increase in Deferred Property Taxes and a $14 million increase in Deferred Income Taxes. The 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 activity in working capital relates to a number of items. The $93 million inflow from Accounts Receivable, Net was primarily due to receiving the SIA refund from the AEP East companies and lower customer receivables. The $37 million inflow from Accrued Taxes, Net was the result of increased accruals related to property and income taxes. The $37 million inflow from Fuel Over/Under-Recovery, Net was primarily due to lower fuel costs. The $29 million outflow from Accounts Payable was primarily due to timing differences for payments to affiliates and payment of items accrued at December 31, 2008.
Net Cash Flows Used for Operating Activities were $40 million in 2008. PSO produced Net Income of $69$37 million during the period and had noncash expense items of $78$26 million for Depreciation and Amortization and $71$38 million for Deferred Income Taxes offset by a $27 million increase in Deferred Property Taxes. PSO established a $72an $80 million regulatory asset for an OCC order approving recovery of ice storm costs related to storms in January and December 2007. The 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 working capital relates to Accounts Payable. Accounts Payable had a number of items. The $81$26 million outflow from Accounts Payable was primarily due to a decreasepayments for ice storm costs accrued at December 31, 2007 offset by an increase in accounts payable accruals and purchased power payable. The $47 million outflow from Fuel Over/Under-Recovery, Net resulted from rapidly increasing natural gas costs which fuels the majority of PSO’s generating facilities. The $36 million inflow from Accrued Taxes, Net was the result of a refund for the 2007 overpayment of federal income taxes and increased accruals related to property and income taxes.
Net Cash Flows from Operating Activities were $62 million in 2007. PSO produced Net Income of $22 million during the period and had a noncash expense item of $70 million for Depreciation and Amortization. The 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 activity in working capital relates to a number of items. The $32 million outflow from Accounts Receivable, Net was primarily due to a receivable booked on behalf of the joint owners of a generating station related to fuel transportation costs. The $26 million inflow from Margin Deposits was primarily due to gas trading activities. The $8 million outflow from Fuel Over/Under Recovery, Net resulted from increasing natural gas costs which fuels the majority of PSO’s generating facilities.fuel.
Investing Activities
Net Cash Flows Used for Investing Activities during 2009 and 2008 and 2007 were $162$59 million and $232$22 million, respectively. Construction Expenditures of $214$52 million and $235$73 million in 20082009 and 2007,2008, respectively, were primarily related to projects for improved generation, transmission and distribution service reliability. In addition, during 2008, PSO had a net decrease of $51 million in loans toinvestments in the Utility Money Pool. For the remainderPSO forecasts approximately $188 million of 2008, PSO expects construction expenditures to be approximately $70 million.for all of 2009, excluding AFUDC.
Financing Activities
Net Cash Flows Used for Financing Activities were $45 million during 2009. PSO had a net decrease of $70 million in borrowings from the Utility Money Pool. PSO issued $34 million of Pollution Control Bonds in February 2009. In addition, PSO paid $7 million in dividends on common stock.
Net Cash Flows from Financing Activities were $120$62 million during 2008. PSO had a net increase of $125$62 million in borrowings from the Utility Money Pool. PSO repurchased $34 million in Pollution Control Bonds in May 2008. PSO received capital contributions from the Parent of $30 million.
Net Cash Flows from Financing Activities were $170 million during 2007. PSO had a net increase of $111 million in borrowings from the Utility Money Pool. PSO received capital contributions from the Parent of $60 million.
Financing Activity
Long-term debt issuances retirements and principal payments maderetirements during the first ninethree months of 20082009 were:
Issuances
| | Principal Amount | | Interest | | Due |
Type of Debt | | | Rate | | Date |
| | (in thousands) | | (%) | | |
Pollution Control Bonds | | $ | 33,700 | | 5.25 | | 2014 |
Retirements
None
Retirements and Principal Payments
| | Principal | | Interest | | Due |
Type of Debt | | Amount Paid | | Rate | | Date |
| | (in thousands) | | (%) | | |
Pollution Control Bonds | | $ | 33,700 | | Variable | | 2014 |
Liquidity
In recent months, theThe financial markets have become increasingly unstable and constrainedremain volatile at both a global and domestic level. This systemic marketplace distress is impactingcould impact PSO’s access to capital, liquidity and cost of capital. The uncertainties in the creditcapital markets could have significant implications on PSO since it relies on continuing access to capital to fund operations and capital expenditures. Management cannot predict the length of time the credit situation will continue or its impact on PSO’s operations and ability to issue debt at reasonable interest rates.
PSO participates in the Utility Money Pool, which provides access to AEP’s liquidity. PSO has $50 million of Senior Unsecured Notes that will mature in June 2009. To the extent refinancing is unavailable due to the challenging credit markets, PSO will rely upon cash flows from operations and access to the Utility Money Pool to fund its maturity, current operations and capital expenditures.
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of liquidity.
Summary Obligation Information
TheA summary of contractual obligations for the year ended 2007 is included in the second quarter 2008 10-QAnnual Report and has not changed significantly from year-end other than the debt retirementissuances discussed in “Cash Flow” and “Financing Activity” above.
Significant Factors
New Generation/Purchased Power Agreement
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section additional discussion of relevant factors.
Litigation and Regulatory Activity
In the ordinary course of business, PSO is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual outcome of these proceedings 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 which have a probable likelihood of loss and the loss amount can be estimated. For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 20072008 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries”. section. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of relevant factors.
Critical Accounting Estimates
See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 20072008 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.
Adoption of New Accounting Pronouncements
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Market Risks
Risk management assets and liabilities are managed by AEPSC as agent. The related risk management policies and procedures are instituted and administered by AEPSC. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on PSO.
MTM Risk Management Contract Net Assets
The following two tables summarize the various mark-to-market (MTM) positions included in PSO’s Condensed Balance Sheet as of September 30, 2008March 31, 2009 and the reasons for changes in total MTM value as compared to December 31, 2007.2008.
Reconciliation of MTM Risk Management Contracts to
Condensed Balance Sheet
As of September 30, 2008March 31, 2009
(in thousands)
| | | | | | | | | | | | |
| | MTM Risk | | | DETM | | | | | | | |
| | Management | | | Assignment | | | Collateral | | | | |
| | Contracts | | | (a) | | | Deposits | | | Total | |
Current Assets | | $ | 25,165 | | | $ | - | | | $ | (448 | ) | | $ | 24,717 | |
Noncurrent Assets | | | 2,703 | | | | - | | | | (51 | ) | | | 2,652 | |
Total MTM Derivative Contract Assets | | | 27,868 | | | | - | | | | (499 | ) | | | 27,369 | |
| | | | | | | | | | | | | | | | |
Current Liabilities | | | (25,508 | ) | | | (110 | ) | | | 40 | | | | (25,578 | ) |
Noncurrent Liabilities | | | (1,891 | ) | | | (112 | ) | | | 7 | | | | (1,996 | ) |
Total MTM Derivative Contract Liabilities | | | (27,399 | ) | | | (222 | ) | | | 47 | | | | (27,574 | ) |
| | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 469 | | | $ | (222 | ) | | $ | (452 | ) | | $ | (205 | ) |
| | MTM Risk Management Contracts | | | Cash Flow Hedge Contracts | | | DETM Assignment (a) | | | Collateral Deposits | | | Total | |
Current Assets | | $ | 7,632 | | | $ | - | | | $ | - | | | $ | - | | | $ | 7,632 | |
Noncurrent Assets | | | 600 | | | | - | | | | - | | | | - | | | | 600 | |
Total MTM Derivative Contract Assets | | | 8,232 | | | | - | | | | - | | | | - | | | | 8,232 | |
| | | | | | | | | | | | | | | | | | | | |
Current Liabilities | | | (5,967 | ) | | | (33 | ) | | | (100 | ) | | | 393 | | | | (5,707 | ) |
Noncurrent Liabilities | | | (312 | ) | | | - | | | | (68 | ) | | | - | | | | (380 | ) |
Total MTM Derivative Contract Liabilities | | | (6,279 | ) | | | (33 | ) | | | (168 | ) | | | 393 | | | | (6,087 | ) |
| | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 1,953 | | | $ | (33 | ) | | $ | (168 | ) | | $ | 393 | | | $ | 2,145 | |
(a) | See “Natural Gas Contracts with DETM” section of Note 1615 of the 20072008 Annual Report. |
MTM Risk Management Contract Net Assets (Liabilities)
NineThree Months Ended September 30, 2008March 31, 2009
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2007 | | $ | 6,981 | |
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | | | (6,988 | ) |
Fair Value of New Contracts at Inception When Entered During the Period (a) | | | - | |
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period | | | - | |
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b) | | | 20 | |
Changes in Fair Value Due to Market Fluctuations During the Period (c) | | | (104 | ) |
Changes in Fair Value Allocated to Regulated Jurisdictions (d) | | | 560 | |
Total MTM Risk Management Contract Net Assets | | | 469 | |
DETM Assignment (e) | | | (222 | ) |
Collateral Deposits | | | (452 | ) |
Ending Net Risk Management Assets (Liabilities) at September 30, 2008 | | $ | (205 | ) |
Total MTM Risk Management Contract Net Assets at December 31, 2008 | | $ | 1,660 | |
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | | | 117 | |
Fair Value of New Contracts at Inception When Entered During the Period (a) | | | - | |
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period | | | - | |
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts | | | - | |
Changes in Fair Value Due to Market Fluctuations During the Period (b) | | | 6 | |
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | | | 170 | |
Total MTM Risk Management Contract Net Assets | | | 1,953 | |
Cash Flow Hedge Contracts | | | (33 | ) |
DETM Assignment (d) | | | (168 | ) |
Collateral Deposits | | | 393 | |
Ending Net Risk Management Assets at March 31, 2009 | | $ | 2,145 | |
(a) | Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged. |
(b) | Represents the impact of applying AEP’s credit risk when measuring the fair value of derivative liabilities according to SFAS 157. |
(c) | Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc. |
(d)(c) | “Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities.liabilities/assets. |
(e)(d) | See “Natural Gas Contracts with DETM” section of Note 1615 of the 20072008 Annual Report. |
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The following table presents the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash:
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2008March 31, 2009
(in thousands)
| | Remainder 2008 | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | After 2012 | | | Total | |
Level 1 (a) | | $ | 316 | | | $ | (250 | ) | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | 66 | |
Level 2 (b) | | | 50 | | | | 1,134 | | | | 511 | | | | (85 | ) | | | - | | | | - | | | | 1,610 | |
Level 3 (c) | | | (1,208 | ) | | | - | | | | 1 | | | | - | | | | - | | | | - | | | | (1,207 | ) |
Total | | $ | (842 | ) | | $ | 884 | | | $ | 512 | | | $ | (85 | ) | | $ | - | | | $ | - | | | $ | 469 | |
| | Remainder 2009 | | | 2010 | | | 2011 | | | 2012 | | | 2013 | | | After 2013 | | | Total | |
Level 1 (a) | | $ | (439 | ) | | $ | (1 | ) | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | (440 | ) |
Level 2 (b) | | | 1,605 | | | | 1,064 | | | | (267 | ) | | | (10 | ) | | | - | | | | - | | | | 2,392 | |
Level 3 (c) | | | - | | | | 1 | | | | - | | | | - | | | | - | | | | - | | | | 1 | |
Total | | $ | 1,166 | | | $ | 1,064 | | | $ | (267 | ) | | $ | (10 | ) | | $ | - | | | $ | - | | | $ | 1,953 | |
(a) | Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis. |
(b) | Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1 and OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market. |
(c) | Level 3 inputs are unobservable inputs for the asset or liability. Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions. |
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed Balance Sheet |
Management uses interest rate derivative transactions to manage interest rate risk related to anticipated borrowings of fixed-rate debt. Management does not hedge all interest rate risk.
The following table provides the detail on designated, effective cash flow hedges included in AOCI on PSO’s Condensed Balance Sheets and the reasons for the changes from December 31, 2007 to September 30, 2008. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2008
(in thousands)
| | Interest Rate | |
Beginning Balance in AOCI December 31, 2007 | | $ | (887 | ) |
Changes in Fair Value | | | - | |
Reclassifications from AOCI for Cash Flow Hedges Settled | | | 137 | |
Ending Balance in AOCI September 30, 2008 | | $ | (750 | ) |
The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is an $183 thousand loss.
Credit Risk
Counterparty credit quality and exposure is generally consistent with that of AEP.
See Note 7 for further information regarding MTM risk management contracts, cash flow hedging, accumulated other comprehensive income, credit risk and collateral triggering events.
VaR Associated with Risk Management Contracts
Management uses a risk measurement model, which calculates Value at Risk (VaR) to measure commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at September 30, 2008,March 31, 2009, a near term typical change in commodity prices is not expected to have a material effect on PSO’s net income, cash flows or financial condition.
The following table shows the end, high, average and low market risk as measured by VaR for the periods indicated:
Nine Months Ended September 30, 2008 | | | | | Twelve Months Ended December 31, 2007 |
(in thousands) | | | | | (in thousands) |
End | | High | | Average | | Low | | | | | End | | High | | Average | | Low |
$69 | | $164 | | $45 | | $8 | | | | | $13 | | $189 | | $53 | | $5 |
Three Months Ended | | | | | Twelve Months Ended |
March 31, 2009 | | | | | December 31, 2008 |
(in thousands) | | | | | (in thousands) |
End | | High | | Average | | Low | | | | | End | | High | | Average | | Low |
$14 | | $34 | | $13 | | $4 | | | | | $4 | | $164 | | $44 | | $6 |
Management back-tests its VaR results against performance due to actual price moves. Based on the assumed 95% confidence interval, the performance due to actual price moves would be expected to exceed the VaR at least once every 20 trading days. Management’s backtesting results show that its actual performance exceeded VaR far fewer than once every 20 trading days. As a result, management believes PSO’s VaR calculation is conservative.
As PSO’s VaR calculation captures recent price moves, management also performs regular stress testing of the portfolio to understand PSO’s exposure to extreme price moves. Management employs a historically-basedhistorical-based method whereby the current portfolio is subjected to actual, observed price moves from the last three years in order to ascertain which historical price moves translatetranslated into the largest potential mark-to-marketMTM loss. Management then researches the underlying positions, price moves and market events that created the most significant exposure.
Interest Rate Risk
Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which PSO’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months. The estimated EaR on PSO’s debt portfolio was $3.6 million.$909 thousand.
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30,March 31, 2009 and 2008 and 2007
(in thousands)
(Unaudited)
| | Three Months Ended | | | Nine Months Ended | |
| | 2008 | | | 2007 | | | 2008 | | | 2007 | |
REVENUES | | | | | | | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 518,182 | | | $ | 433,737 | | | $ | 1,194,737 | | | $ | 1,028,637 | |
Sales to AEP Affiliates | | | 32,286 | | | | 12,737 | | | | 89,988 | | | | 53,605 | |
Other | | | 781 | | | | 1,562 | | | | 2,858 | | | | 2,746 | |
TOTAL | | | 551,249 | | | | 448,036 | | | | 1,287,583 | | | | 1,084,988 | |
| | | | | | | | | | | | | | | | |
EXPENSES | | | | | | | | | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 288,027 | | | | 182,680 | | | | 584,769 | | | | 438,828 | |
Purchased Electricity for Resale | | | 77,834 | | | | 75,875 | | | | 230,432 | | | | 213,429 | |
Purchased Electricity from AEP Affiliates | | | 15,169 | | | | 16,216 | | | | 53,944 | | | | 48,679 | |
Other Operation | | | 51,432 | | | | 44,030 | | | | 152,617 | | | | 127,382 | |
Maintenance | | | 27,530 | | | | 24,128 | | | | 87,772 | | | | 89,390 | |
Deferral of Ice Storm Costs | | | 69 | | | | - | | | | (71,610 | ) | | | - | |
Depreciation and Amortization | | | 27,192 | | | | 24,430 | | | | 78,079 | | | | 70,128 | |
Taxes Other Than Income Taxes | | | 7,839 | | | | 10,007 | | | | 29,265 | | | | 30,191 | |
TOTAL | | | 495,092 | | | | 377,366 | | | | 1,145,268 | | | | 1,018,027 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 56,157 | | | | 70,670 | | | | 142,315 | | | | 66,961 | |
| | | | | | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | | | | | |
Other Income | | | 34 | | | | 1,086 | | | | 4,004 | | | | 2,294 | |
Carrying Costs Income | | | 3,183 | | | | - | | | | 6,945 | | | | - | |
Interest Expense | | | (13,713 | ) | | | (12,381 | ) | | | (43,179 | ) | | | (36,549 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 45,661 | | | | 59,375 | | | | 110,085 | | | | 32,706 | |
| | | | | | | | | | | | | | | | |
Income Tax Expense | | | 17,917 | | | | 22,804 | | | | 40,815 | | | | 10,266 | |
| | | | | | | | | | | | | | | | |
NET INCOME | | | 27,744 | | | | 36,571 | | | | 69,270 | | | | 22,440 | |
| | | | | | | | | | | | | | | | |
Preferred Stock Dividend Requirements | | | 53 | | | | 53 | | | | 159 | | | | 159 | |
| | | | | | | | | | | | | | | | |
EARNINGS APPLICABLE TO COMMON STOCK | | $ | 27,691 | | | $ | 36,518 | | | $ | 69,111 | | | $ | 22,281 | |
| | 2009 | | | 2008 | |
REVENUES | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 278,771 | | | $ | 318,880 | |
Sales to AEP Affiliates | | | 15,823 | | | | 15,935 | |
Other | | | 693 | | | | 1,185 | |
TOTAL | | | 295,287 | | | | 336,000 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 119,399 | | | | 153,205 | |
Purchased Electricity for Resale | | | 44,425 | | | | 48,582 | |
Purchased Electricity from AEP Affiliates | | | 5,915 | | | | 17,269 | |
Other Operation | | | 39,545 | | | | 55,999 | |
Maintenance | | | 25,430 | | | | 34,587 | |
Deferral of Ice Storm Costs | | | - | | | | (79,902 | ) |
Depreciation and Amortization | | | 27,950 | | | | 26,167 | |
Taxes Other Than Income Taxes | | | 10,751 | | | | 10,952 | |
TOTAL | | | 273,415 | | | | 266,859 | |
| | | | | | | | |
OPERATING INCOME | | | 21,872 | | | | 69,141 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest Income | | | 648 | | | | 1,128 | |
Carrying Costs Income | | | 1,711 | | | | 1,634 | |
Allowance for Equity Funds Used During Construction | | | 170 | | | | 1,359 | |
Interest Expense | | | (14,805 | ) | | | (14,941 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 9,596 | | | | 58,321 | |
| | | | | | | | |
Income Tax Expense | | | 3,558 | | | | 20,922 | |
| | | | | | | | |
NET INCOME | | | 6,038 | | | | 37,399 | |
| | | | | | | | |
Preferred Stock Dividend Requirements | | | 53 | | | | 53 | |
| | | | | | | | |
EARNINGS ATTRIBUTABLE TO COMMON STOCK | | $ | 5,985 | | | $ | 37,346 | |
The common stock of PSO is wholly-owned by AEP. |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the NineThree Months Ended September 30,March 31, 2009 and 2008 and 2007
(in thousands)
(Unaudited)
| | Common Stock | | | Paid-in Capital | | | Retained Earnings | | | Accumulated Other Comprehensive Income (Loss) | | | Total | |
DECEMBER 31, 2006 | | $ | 157,230 | | | $ | 230,016 | | | $ | 199,262 | | | $ | (1,070 | ) | | $ | 585,438 | |
| | | | | | | | | | | | | | | | | | | | |
FIN 48 Adoption, Net of Tax | | | | | | | | | | | (386 | ) | | | | | | | (386 | ) |
Capital Contribution from Parent | | | | | | | 60,000 | | | | | | | | | | | | 60,000 | |
Preferred Stock Dividends | | | | | | | | | | | (159 | ) | | | | | | | (159 | ) |
TOTAL | | | | | | | | | | | | | | | | | | | 644,893 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $74 | | | | | | | | | | | | | | | 137 | | | | 137 | |
NET INCOME | | | | | | | | | | | 22,440 | | | | | | | | 22,440 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 22,577 | |
| | | | | | | | | | | | | | | | | | | | |
SEPTEMBER 30, 2007 | | $ | 157,230 | | | $ | 290,016 | | | $ | 221,157 | | | $ | (933 | ) | | $ | 667,470 | |
| | | | | | | | | | | | | | | | | | | | |
DECEMBER 31, 2007 | | $ | 157,230 | | | $ | 310,016 | | | $ | 174,539 | | | $ | (887 | ) | | $ | 640,898 | |
| | | | | | | | | | | | | | | | | | | | |
EITF 06-10 Adoption, Net of Tax of $596 | | | | | | | | | | | (1,107 | ) | | | | | | | (1,107 | ) |
Capital Contribution from Parent | | | | | | | 30,000 | | | | | | | | | | | | 30,000 | |
Preferred Stock Dividends | | | | | | | | | | | (159 | ) | | | | | | | (159 | ) |
TOTAL | | | | | | | | | | | | | | | | | | | 669,632 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $74 | | | | | | | | | | | | | | | 137 | | | | 137 | |
NET INCOME | | | | | | | | | | | 69,270 | | | | | | | | 69,270 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 69,407 | |
| | | | | | | | | | | | | | | | | | | | |
SEPTEMBER 30, 2008 | | $ | 157,230 | | | $ | 340,016 | | | $ | 242,543 | | | $ | (750 | ) | | $ | 739,039 | |
| | Common Stock | | | Paid-in Capital | | | Retained Earnings | | | Accumulated Other Comprehensive (Loss) | | | Total | |
| | | | | | | | | | | | | | | |
DECEMBER 31, 2007 | | $ | 157,230 | | | $ | 310,016 | | | $ | 174,539 | | | $ | (887 | ) | | $ | 640,898 | |
| | | | | | | | | | | | | | | | | | | | |
EITF 06-10 Adoption, Net of Tax of $596 | | | | | | | | | | | (1,107 | ) | | | | | | | (1,107 | ) |
Preferred Stock Dividends | | | | | | | | | | | (53 | ) | | | | | | | (53 | ) |
TOTAL | | | | | | | | | | | | | | | | | | | 639,738 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $24 | | | | | | | | | | | | | | | 45 | | | | 45 | |
NET INCOME | | | | | | | | | | | 37,399 | | | | | | | | 37,399 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 37,444 | |
| | | | | | | | | | | | | | | | | | | | |
MARCH 31, 2008 | | $ | 157,230 | �� | | $ | 310,016 | | | $ | 210,778 | | | $ | (842 | ) | | $ | 677,182 | |
| | | | | | | | | | | | | | | | | | | | |
DECEMBER 31, 2008 | | $ | 157,230 | | | $ | 340,016 | | | $ | 251,704 | | | $ | (704 | ) | | $ | 748,246 | |
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (7,250 | ) | | | | | | | (7,250 | ) |
Preferred Stock Dividends | | | | | | | | | | | (53 | ) | | | | | | | (53 | ) |
Other | | | | | | | 4,214 | | | | (4,214 | ) | | | | | | | - | |
TOTAL | | | | | | | | | | | | | | | | | | | 740,943 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $12 | | | | | | | | | | | | | | | 22 | | | | 22 | |
NET INCOME | | | | | | | | | | | 6,038 | | | | | | | | 6,038 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 6,060 | |
| | | | | | | | | | | | | | | | | | | | |
MARCH 31, 2009 | | $ | 157,230 | | | $ | 344,230 | | | $ | 246,225 | | | $ | (682 | ) | | $ | 747,003 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
ASSETS
September 30, 2008March 31, 2009 and December 31, 20072008
(in thousands)
(Unaudited)
| | 2008 | | | 2007 | |
CURRENT ASSETS | | | |
Cash and Cash Equivalents | | $ | 2,244 | | | $ | 1,370 | |
Advances to Affiliates | | | - | | | | 51,202 | |
Accounts Receivable: | | | | | | | | |
Customers | | | 42,023 | | | | 74,330 | |
Affiliated Companies | | | 72,627 | | | | 59,835 | |
Miscellaneous | | | 9,716 | | | | 10,315 | |
Allowance for Uncollectible Accounts | | | (28 | ) | | | - | |
Total Accounts Receivable | | | 124,338 | | | | 144,480 | |
Fuel | | | 26,547 | | | | 19,394 | |
Materials and Supplies | | | 47,419 | | | | 47,691 | |
Risk Management Assets | | | 24,717 | | | | 33,308 | |
Accrued Tax Benefits | | | 13,040 | | | | 31,756 | |
Regulatory Asset for Under-Recovered Fuel Costs | | | 35,495 | | | | - | |
Margin Deposits | | | 426 | | | | 8,980 | |
Prepayments and Other | | | 18,385 | | | | 18,137 | |
TOTAL | | | 292,611 | | | | 356,318 | |
| | | �� | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Production | | | 1,252,804 | | | | 1,110,657 | |
Transmission | | | 601,518 | | | | 569,746 | |
Distribution | | | 1,437,156 | | | | 1,337,038 | |
Other | | | 253,886 | | | | 241,722 | |
Construction Work in Progress | | | 77,392 | | | | 200,018 | |
Total | | | 3,622,756 | | | | 3,459,181 | |
Accumulated Depreciation and Amortization | | | 1,191,777 | | | | 1,182,171 | |
TOTAL - NET | | | 2,430,979 | | | | 2,277,010 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 186,216 | | | | 158,731 | |
Long-term Risk Management Assets | | | 2,652 | | | | 3,358 | |
Deferred Charges and Other | | | 59,369 | | | | 48,454 | |
TOTAL | | | 248,237 | | | | 210,543 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 2,971,827 | | | $ | 2,843,871 | |
| | 2009 | | | 2008 | |
CURRENT ASSETS | | | |
Cash and Cash Equivalents | | $ | 1,277 | | | $ | 1,345 | |
Advances to Affiliates | | | 7,009 | | | | - | |
Accounts Receivable: | | | | | | | | |
Customers | | | 29,010 | | | | 39,823 | |
Affiliated Companies | | | 60,513 | | | | 138,665 | |
Miscellaneous | | | 4,955 | | | | 8,441 | |
Allowance for Uncollectible Accounts | | | (130 | ) | | | (20 | ) |
Total Accounts Receivable | | | 94,348 | | | | 186,909 | |
Fuel | | | 24,739 | | | | 27,060 | |
Materials and Supplies | | | 44,982 | | | | 44,047 | |
Risk Management Assets | | | 7,632 | | | | 5,830 | |
Deferred Tax Benefits | | | 33,624 | | | | 9,123 | |
Accrued Tax Benefits | | | - | | | | 3,876 | |
Prepayments and Other | | | 6,607 | | | | 3,371 | |
TOTAL | | | 220,218 | | | | 281,561 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Production | | | 1,273,326 | | | | 1,266,716 | |
Transmission | | | 628,733 | | | | 622,665 | |
Distribution | | | 1,493,418 | | | | 1,468,481 | |
Other | | | 248,238 | | | | 248,897 | |
Construction Work in Progress | | | 83,239 | | | | 85,252 | |
Total | | | 3,726,954 | | | | 3,692,011 | |
Accumulated Depreciation and Amortization | | | 1,204,894 | | | | 1,192,130 | |
TOTAL - NET | | | 2,522,060 | | | | 2,499,881 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 300,305 | | | | 304,737 | |
Long-term Risk Management Assets | | | 600 | | | | 917 | |
Deferred Charges and Other | | | 39,088 | | | | 13,702 | |
TOTAL | | | 339,993 | | | | 319,356 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 3,082,271 | | | $ | 3,100,798 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2008March 31, 2009 and December 31, 20072008
(Unaudited)
| | 2008 | | | 2007 | |
CURRENT LIABILITIES | | (in thousands) | |
Advances from Affiliates | | $ | 125,029 | | | $ | - | |
Accounts Payable: | | | | | | | | |
General | | | 98,541 | | | | 189,032 | |
Affiliated Companies | | | 74,420 | | | | 80,316 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 50,000 | | | | - | |
Risk Management Liabilities | | | 25,578 | | | | 27,118 | |
Customer Deposits | | | 39,498 | | | | 41,477 | |
Accrued Taxes | | | 35,282 | | | | 18,374 | |
Regulatory Liability for Over-Recovered Fuel Costs | | | - | | | | 11,697 | |
Other | | | 46,703 | | | | 57,708 | |
TOTAL | | | 495,051 | | | | 425,722 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 834,798 | | | | 918,316 | |
Long-term Risk Management Liabilities | | | 1,996 | | | | 2,808 | |
Deferred Income Taxes | | | 530,293 | | | | 456,497 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 316,521 | | | | 338,788 | |
Deferred Credits and Other | | | 48,867 | | | | 55,580 | |
TOTAL | | | 1,732,475 | | | | 1,771,989 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 2,227,526 | | | | 2,197,711 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 5,262 | | | | 5,262 | |
| | | | | | | | |
Commitments and Contingencies (Note 4) | | | | | | | | |
| | | | | | | | |
COMMON SHAREHOLDER’S EQUITY | | | | | | | | |
Common Stock – $15 Par Value Per Share: | | | | | | | | |
Authorized – 11,000,000 Shares | | | | | | | | |
Issued – 10,482,000 Shares | | | | | | | | |
Outstanding – 9,013,000 Shares | | | 157,230 | | | | 157,230 | |
Paid-in Capital | | | 340,016 | | | | 310,016 | |
Retained Earnings | | | 242,543 | | | | 174,539 | |
Accumulated Other Comprehensive Income (Loss) | | | (750 | ) | | | (887 | ) |
TOTAL | | | 739,039 | | | | 640,898 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 2,971,827 | | | $ | 2,843,871 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2008 and 2007
(in thousands)
(Unaudited)
| | 2008 | | | 2007 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 69,270 | | | $ | 22,440 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 78,079 | | | | 70,128 | |
Deferred Income Taxes | | | 70,856 | | | | 23,220 | |
Deferral of Ice Storm Costs | | | (71,610 | ) | | | - | |
Allowance for Equity Funds Used During Construction | | | (1,840 | ) | | | (649 | ) |
Mark-to-Market of Risk Management Contracts | | | 6,973 | | | | 7,120 | |
Change in Other Noncurrent Assets | | | 9,920 | | | | (17,754 | ) |
Change in Other Noncurrent Liabilities | | | (34,426 | ) | | | (31,165 | ) |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 21,846 | | | | (31,617 | ) |
Fuel, Materials and Supplies | | | (6,881 | ) | | | (2,110 | ) |
Margin Deposits | | | 8,554 | | | | 26,461 | |
Accounts Payable | | | (81,228 | ) | | | 10,226 | |
Accrued Taxes, Net | | | 35,624 | | | | 19,725 | |
Fuel Over/Under-Recovery, Net | | | (47,192 | ) | | | (8,260 | ) |
Other Current Assets | | | (1,676 | ) | | | 177 | |
Other Current Liabilities | | | (13,883 | ) | | | (25,900 | ) |
Net Cash Flows from Operating Activities | | | 42,386 | | | | 62,042 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (214,319 | ) | | | (235,089 | ) |
Change in Advances to Affiliates, Net | | | 51,202 | | | | - | |
Other | | | 1,594 | | | | 3,173 | |
Net Cash Flows Used for Investing Activities | | | (161,523 | ) | | | (231,916 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Capital Contribution from Parent | | | 30,000 | | | | 60,000 | |
Issuance of Long-term Debt – Nonaffiliated | | | - | | | | 12,488 | |
Change in Advances from Affiliates, Net | | | 125,029 | | | | 111,169 | |
Retirement of Long-term Debt – Affiliated | | | (33,700 | ) | | | (12,660 | ) |
Principal Payments for Capital Lease Obligations | | | (1,159 | ) | | | (1,125 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (159 | ) | | | (159 | ) |
Net Cash Flows from Financing Activities | | | 120,011 | | | | 169,713 | |
| | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 874 | | | | (161 | ) |
Cash and Cash Equivalents at Beginning of Period | | | 1,370 | | | | 1,651 | |
Cash and Cash Equivalents at End of Period | | $ | 2,244 | | | $ | 1,490 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 39,739 | | | $ | 34,427 | |
Net Cash Received for Income Taxes | | | 44,559 | | | | 18,004 | |
Noncash Acquisitions Under Capital Leases | | | 403 | | | | 600 | |
Construction Expenditures Included in Accounts Payable at September 30, | | | 12,251 | | | | 16,358 | |
| | 2009 | | | 2008 | |
CURRENT LIABILITIES | | (in thousands) | |
Advances from Affiliates | | $ | - | | | $ | 70,308 | |
Accounts Payable: | | | | | | | | |
General | | | 68,187 | | | | 84,121 | |
Affiliated Companies | | | 67,490 | | | | 86,407 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 50,000 | | | | 50,000 | |
Risk Management Liabilities | | | 5,707 | | | | 4,753 | |
Customer Deposits | | | 41,967 | | | | 40,528 | |
Accrued Taxes | | | 51,818 | | | | 19,000 | |
Regulatory Liability for Over-Recovered Fuel Costs | | | 147,199 | | | | 58,395 | |
Provision for Revenue Refund | | | - | | | | 52,100 | |
Other | | | 39,606 | | | | 61,194 | |
TOTAL | | | 471,974 | | | | 526,806 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 868,619 | | | | 834,859 | |
Long-term Risk Management Liabilities | | | 380 | | | | 378 | |
Deferred Income Taxes | | | 523,842 | | | | 514,720 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 324,693 | | | | 323,750 | |
Deferred Credits and Other | | | 140,498 | | | | 146,777 | |
TOTAL | | | 1,858,032 | | | | 1,820,484 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 2,330,006 | | | | 2,347,290 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 5,262 | | | | 5,262 | |
| | | | | | | | |
Commitments and Contingencies (Note 4) | | | | | | | | |
| | | | | | | | |
COMMON SHAREHOLDER’S EQUITY | | | | | | | | |
Common Stock – Par Value – $15 Per Share: | | | | | | | | |
Authorized – 11,000,000 Shares | | | | | | | | |
Issued – 10,482,000 Shares | | | | | | | | |
Outstanding – 9,013,000 Shares | | | 157,230 | | | | 157,230 | |
Paid-in Capital | | | 344,230 | | | | 340,016 | |
Retained Earnings | | | 246,225 | | | | 251,704 | |
Accumulated Other Comprehensive Income (Loss) | | | (682 | ) | | | (704 | ) |
TOTAL | | | 747,003 | | | | 748,246 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 3,082,271 | | | $ | 3,100,798 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
CONDENSED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2009 and 2008
(in thousands)
(Unaudited)
| | 2009 | | | 2008 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 6,038 | | | $ | 37,399 | |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 27,950 | | | | 26,167 | |
Deferred Income Taxes | | | (13,835 | ) | | | 37,899 | |
Deferral of Ice Storm Costs | | | - | | | | (79,902 | ) |
Allowance for Equity Funds Used During Construction | | | (170 | ) | | | (1,359 | ) |
Mark-to-Market of Risk Management Contracts | | | (562 | ) | | | (11,881 | ) |
Deferred Property Taxes | | | (28,050 | ) | | | (26,694 | ) |
Change in Other Noncurrent Assets | | | (1,282 | ) | | | 22,022 | |
Change in Other Noncurrent Liabilities | | | (1,879 | ) | | | (20,541 | ) |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 92,561 | | | | (5,027 | ) |
Fuel, Materials and Supplies | | | 1,386 | | | | (5,086 | ) |
Accounts Payable | | | (28,623 | ) | | | (25,698 | ) |
Accrued Taxes, Net | | | 36,694 | | | | 22,107 | |
Fuel Over/Under-Recovery, Net | | | 36,650 | | | | 4,572 | |
Other Current Assets | | | (3,511 | ) | | | 6,976 | |
Other Current Liabilities | | | (19,564 | ) | | | (20,759 | ) |
Net Cash Flows from (Used for) Operating Activities | | | 103,803 | | | | (39,805 | ) |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (52,368 | ) | | | (73,203 | ) |
Change in Advances to Affiliates, Net | | | (7,009 | ) | | | 51,202 | |
Proceeds from Sales of Assets | | | 232 | | | | 148 | |
Net Cash Flows Used for Investing Activities | | | (59,145 | ) | | | (21,853 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Long-term Debt – Nonaffiliated | | | 33,283 | | | | - | |
Change in Advances from Affiliates, Net | | | (70,308 | ) | | | 62,159 | |
Principal Payments for Capital Lease Obligations | | | (398 | ) | | | (383 | ) |
Dividends Paid on Common Stock | | | (7,250 | ) | | | - | |
Dividends Paid on Cumulative Preferred Stock | | | (53 | ) | | | (53 | ) |
Net Cash Flows from (Used for) Financing Activities | | | (44,726 | ) | | | 61,723 | |
| | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | (68 | ) | | | 65 | |
Cash and Cash Equivalents at Beginning of Period | | | 1,345 | | | | 1,370 | |
Cash and Cash Equivalents at End of Period | | $ | 1,277 | | | $ | 1,435 | |
SUPPLEMENTARY INFORMATION | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 29,174 | | | $ | 12,380 | |
Net Cash Paid (Received) for Income Taxes | | | 391 | | | | (19,408 | ) |
Noncash Acquisitions Under Capital Leases | | | 391 | | | | 135 | |
Construction Expenditures Included in Accounts Payable at March 31, | | | 11,776 | | | | 21,086 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The condensed notes to PSO’s condensed financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to PSO.
| Footnote Reference |
| |
Significant Accounting Matters | Note 1 |
New Accounting Pronouncements and Extraordinary Item | Note 2 |
Rate Matters | Note 3 |
Commitments, Guarantees and Contingencies | Note 4 |
Benefit Plans | Note 65 |
Business Segments | Note 6 |
Derivatives, Hedging and Fair Value Measurements | Note 7 |
Income Taxes | Note 8 |
Financing Activities | Note 9 |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
ThirdFirst Quarter of 20082009 Compared to ThirdFirst Quarter of 20072008
Reconciliation of ThirdFirst Quarter of 20072008 to ThirdFirst Quarter of 20082009
Net Income
(in millions)
Third Quarter of 2007 | | | | | $ | 44 | |
| | | | | | | |
Changes in Gross Margin: | | | | | | | |
Retail and Off-system Sales Margins (a) | | | 11 | | | | | |
Transmission Revenues | | | 3 | | | | | |
Other | | | 3 | | | | | |
Total Change in Gross Margin | | | | | | | 17 | |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | (15 | ) | | | | |
Depreciation and Amortization | | | (1 | ) | | | | |
Taxes Other Than Income Taxes | | | 4 | | | | | |
Other Income | | | 5 | | | | | |
Interest Expense | | | (7 | ) | | | | |
Total Change in Operating Expenses and Other | | | | | | | (14 | ) |
| | | | | | | | |
Third Quarter of 2008 | | | | | | $ | 47 | |
First Quarter of 2008 | | | | | $ | 6 | |
| | | | | | | |
Changes in Gross Margin: | | | | | | | |
Retail and Off-system Sales Margins (a) | | | (3 | ) | | | | |
Transmission Revenues | | | 2 | | | | | |
Other | | | (2 | ) | | | | |
Total Change in Gross Margin | | | | | | | (3 | ) |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | 10 | | | | | |
Depreciation and Amortization | | | (1 | ) | | | | |
Taxes Other Than Income Taxes | | | 2 | | | | | |
Other Income | | | 3 | | | | | |
Interest Expense | | | 1 | | | | | |
Total Change in Operating Expenses and Other | | | | | | | 15 | |
| | | | | | | | |
Income Tax Expense | | | | | | | (6 | ) |
| | | | | | | | |
First Quarter of 2009 | | | | | | $ | 12 | |
(a) | Includes firm wholesale sales to municipals and cooperatives. |
Net Income increased $3$6 million to $47$12 million in 2008.2009. The key drivers of the increase were a $17$15 million increasedecrease in Gross Margin,Operating Expenses and Other, partially offset by a $14$6 million increase in Operating ExpensesIncome Tax Expense and Other.a $3 million decrease in Gross Margin.
The major components of the increasedecrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:
· | Retail and Off-system Sales Margins increased $11decreased $3 million primarily due to an increasea $4 million decrease in wholesale fuel recovery.retail sales margins primarily related to reduced customer usage, partially offset by increased rates related to the Louisiana Formula Rate Plan. |
· | Transmission Revenues increased $3$2 million primarily due to higher rates in the SPP region. |
· | Other revenues increased $3decreased $2 million primarily due to an increasea decrease in revenues from coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills Lignite Company, LLC to Cleco Corporation, a nonaffiliated entity.entity and decreased gain on sales of emission allowances. The increase in coal deliveries was the result of planned and forced outages during 2007 at the Dolet Hills Generating Station, which is jointly-owned by SWEPCo and Cleco Corporation. The increaseddecreased revenue from coal deliveries was offset by a corresponding increase in Other Operation and Maintenance expenses from mining operations as discussed below. |
Operating Expenses and Other changed between years as follows:
· | Other Operation and Maintenance expenses increased $15 million primarily due to the following: |
| · | A $14 million increase in distribution expenses primarily due to storm restoration expenses for Hurricanes Ike and Gustav. SWEPCo intends to pursue the recovery of these expenses. |
| · | A $3 million increase in expense for coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills Lignite Company, LLC. The increased expenses for coal deliveries were offset by a corresponding increase in revenues from mining operations as discussed above. |
· | Taxes Other Than Income Taxes decreased $4 million primarily due to a $3 million decrease in state and local franchise tax from refunds related to prior years. |
· | Other Income increased $5 million primarily due to higher nonaffiliated interest income resulting from the fuel under-recovery balance, the Texas state franchise refund and the Utility Money Pool. |
· | Interest Expense increased $7 million primarily due to a $10 million increase related to higher long-term debt outstanding, partially offset by a $3 million increase in the debt component of AFUDC due to new generation projects. |
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
Net Income
(in millions)
Nine Months Ended September 30, 2007 | | | | | $ | 55 | |
| | | | | | | |
Changes in Gross Margin: | | | | | | | |
Retail and Off-system Sales Margins (a) | | | 38 | | | | | |
Transmission Revenues | | | 7 | | | | | |
Other | | | - | | | | | |
Total Change in Gross Margin | | | | | | | 45 | |
| | | | | | | | |
Changes in Operating Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | (33 | ) | | | | |
Depreciation and Amortization | | | (5 | ) | | | | |
Taxes Other Than Income Taxes | | | 5 | | | | | |
Other Income | | | 8 | | | | | |
Interest Expense | | | (8 | ) | | | | |
Total Change in Operating Expenses and Other | | | | | | | (33 | ) |
| | | | | | | | |
Income Tax Expense | | | | | | | (1 | ) |
| | | | | | | | |
Nine Months Ended September 30, 2008 | | | | | | $ | 66 | |
(a) | Includes firm wholesale sales to municipals and cooperatives. |
Net Income increased $11 million to $66 million in 2008. The key drivers of the increase were a $45 million increase in Gross Margin, partially offset by a $33 million increase in Operating Expenses and Other.
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:
· | Retail and Off-system Sales Margins increased $38 million primarily due to higher fuel recovery resulting from an $18 million refund provision booked in 2007 pursuant to an unfavorable ALJ ruling in the Texas Fuel Reconciliation proceeding. In addition, an increase of $10 million in wholesale revenue and lower purchase power capacity of $4 million was reflected in 2008. |
· | Transmission Revenues increased $7 million due to higher rates in the SPP region. |
· | While Other revenues in total were unchanged, there was a $12 million decrease in gains on sales of emission allowances. This decrease was offset by an $11 million increase in revenue from coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills Lignite Company, LLC, to Cleco Corporation, a nonaffiliated entity. The increase in coal deliveries was the result of planned and forced outages during 2007 at the Dolet Hills Generating Station, which is jointly-owned by SWEPCo and Cleco Corporation. The increased revenue from coal deliveries was offset by a corresponding increase in Other Operation and Maintenance expenses from mining operations as discussed below. |
Operating Expenses and Other and Income Tax Expense changed between years as follows:
· | Other Operation and Maintenance expenses increased $33decreased $10 million primarily due to the following:to: |
| · | A $12$5 million increasedecrease in distribution expenses primarily due to storm restoration expenses from Hurricanes Ike and Gustav. SWEPCo intends to pursue the recoveryoperation expense as a result of theselower employee-related expenses. |
| · | A $14$2 million increasegain on sale of property related to the sale of percentage ownership of Turk Plant to nonaffiliated companies who exercised their participation options. |
| · | A $2 million decrease in expenses for coal deliveries from SWEPCo’s mining subsidiary, Dolet Hills Lignite Company, LLC. The increaseddecreased expenses for coal deliveries were partially offset by a corresponding increasedecrease in revenues from mining operations as discussed above. |
· | Depreciation and Amortization increased $5 million primarily due to higher depreciable asset balances. |
· | Taxes Other Than Income Taxes decreased $5$2 million primarily due to a decrease in statelower property tax and local franchise tax from refunds related to prior years.revenue tax. |
· | Other Income increased $8$3 million primarily due to higher nonaffiliated interest income and an increase in the AFUDC equity component of AFUDC as a result of new generation projects. |
· | Interest Expense increased $8 million primarily due to a $17 million increase from higher long-term debt outstanding, partially offset by a $7 million increase inconstruction at the debt component of AFUDC due to new generation projects.Turk Plant and Stall Unit. See Note 3. |
· | Income Tax Expense increased $1$6 million primarily due to an increase in pretaxpre-tax book income partially offset by stateand prior year income taxes and changes in certain book/tax differences accounted for on a flow-through basis.adjustments. |
Financial Condition
Credit Ratings
S&P and Fitch currently have SWEPCo on stable outlook, while Moody’s placed SWEPCo on negative outlook in the first quarter of 2008. In addition, in the first quarter of 2008, Fitch downgraded SWEPCo from A- to BBB+ for senior unsecured debt. CurrentSWEPCo’s credit ratings areas of March 31, 2009 were as follows:
| Moody’s | | S&P | | Fitch |
| | | | | |
Senior Unsecured Debt | Baa1 | | BBB | | BBB+ |
IfS&P and Fitch have SWEPCo receives an upgrade from any of the rating agencies listed above, its borrowing costs could decrease.on stable outlook. In 2009, Moody’s placed SWEPCo on review for possible downgrade due to concerns about financial metrics and pending cost and construction recoveries. If SWEPCo receives a downgrade from any of the rating agencies, listed above, its borrowing costs could increase and access to borrowed funds could be negatively affected.
Cash Flow
Cash flows for the ninethree months ended September 30,March 31, 2009 and 2008 and 2007 were as follows:
| | 2008 | | | 2007 | |
| | (in thousands) | |
Cash and Cash Equivalents at Beginning of Period | | $ | 1,742 | | | $ | 2,618 | |
Cash Flows from (Used for): | | | | | | | | |
Operating Activities | | | 130,250 | | | | 180,146 | |
Investing Activities | | | (619,487 | ) | | | (353,001 | ) |
Financing Activities | | | 490,247 | | | | 172,089 | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 1,010 | | | | (766 | ) |
Cash and Cash Equivalents at End of Period | | $ | 2,752 | | | $ | 1,852 | |
| | 2009 | | | 2008 | |
| | (in thousands) | |
Cash and Cash Equivalents at Beginning of Period | | $ | 1,910 | | | $ | 1,742 | |
Cash Flows from (Used for): | | | | | | | | |
Operating Activities | | | 93,470 | | | | (3,153 | ) |
Investing Activities | | | (103,382 | ) | | | (125,877 | ) |
Financing Activities | | | 9,739 | | | | 133,191 | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | (173 | ) | | | 4,161 | |
Cash and Cash Equivalents at End of Period | | $ | 1,737 | | | $ | 5,903 | |
Operating Activities
Net Cash Flows from Operating Activities were $130$93 million in 2008.2009. SWEPCo produced Net Income of $66$12 million during the period and had a noncash expense item of $109$37 million for Depreciation and Amortization, $30 million for Deferred Property Taxes and $37$27 million for Deferred Income Taxes. The 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 activity in working capital relates to a number of items. The $99 million outflow from Fuel Over/Under-Recovery, Net was the result of higher fuel costs. The $47$95 million inflow from Accounts Receivable, Net was primarily due to the assignmentreceipt of certain ERCOT contracts to an affiliate company.payment for SIA from the AEP East companies. The $35 million outflow from Accounts Payable was primarily due to a decrease in purchased power payables. The $29$59 million inflow from Accrued Taxes, Net was the result of increased accruals related to income and property taxes. The $50 million outflow from Other Current Liabilities was due to a decrease in checks outstanding, a refund to wholesale customers for the 2007 overpaymentSIA and payments of federal income taxes.employee-related expenses. The $27 million inflow from Fuel Over/Under-Recovery, Net was the result of a decrease in fuel costs in relation to the recovery of these costs from customers. The $20 million outflow from Accrued Interest was due to increased long-term debt outstanding as well as the timing of interest payments in relation to the accruals for payments.
Net Cash Flows fromUsed for Operating Activities were $180$3 million in 2007.2008. SWEPCo produced Net Income of $55$6 million during the period and had a noncash expense itemsitem of $103$36 million for Depreciation and Amortization and $24 million related to the Provision for Fuel Disallowance recorded as the result of an ALJ ruling in SWEPCo’s Texas fuel reconciliation proceeding.Amortization. The 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 activity in working capital relates to a number of items. The $48$40 million outflow from Fuel Over/Under-Recovery, Net was the result of higher fuel costs. The $22 million inflow from Accounts Receivable, Net was primarily due to the assignment of certain ERCOT contracts to an affiliate company. The $30$21 million inflow from Margin DepositsAccrued Taxes, Net was duethe result of increased accruals related to decreased trading-related deposits resulting from normal trading activities. The $27 million outflow from Fuel Over/Under Recovery, Net is due to under recovery of higher fuel costs.property and income taxes.
Investing Activities
Net Cash Flows Used for Investing Activities during 2009 and 2008 and 2007 were $619$103 million and $353$126 million, respectively. Construction Expenditures of $424$170 million and $353$125 million in 20082009 and 2007,2008, respectively, were primarily related to new generation projects at the Turk Plant Mattison Plant and Stall Unit. In addition, during 2008, SWEPCo had a net increaseProceeds from Sales of $196Assets in 2009 primarily includes $104 million in loansprogress payments for Turk Plant construction from the joint owners. Change in Advances to Affiliates, Net of $38 million in 2009 was primarily due to the Utility Money Pool. For the remaindercontribution from Parent and net income. SWEPCo forecasts approximately $457 million of 2008, SWEPCo expects construction expenditures to be approximately $250 million.for all of 2009, excluding AFUDC.
Financing Activities
Net Cash Flows from Financing Activities were $490$10 million during 2008. SWEPCo issued $400 million of Senior Unsecured Notes.2009. SWEPCo received a Capital Contribution from Parent of $100$18 million. SWEPCo retired $46had a net decrease of $3 million of Nonaffiliated Long-term Debt.in borrowings from the Utility Money Pool.
Net Cash Flows from Financing Activities were $172$133 million during 2007. SWEPCo issued $250 million of Senior Unsecured Notes and retired $90 million of First Mortgage Bonds.2008. SWEPCo received a Capital Contribution from Parent of $55$50 million. SWEPCo also reduced itshad a net increase of $88 million in borrowings from the Utility Money Pool by $33 million.Pool.
Financing Activity
Long-term debt issuances retirements and principal payments made during the first ninethree months of 20082009 were:
Issuances
| | Principal Amount | | Interest | | Due |
Type of Debt | | | Rate | | Date |
| | (in thousands) | | (%) | | |
Senior Unsecured Notes | | $ | 400,000 | | 6.45 | | 2019 |
Pollution Control Bonds | | | 41,135 | | 4.50 | | 2011 |
None
Retirements and Principal Payments
| | Principal Amount Paid | | Interest | | Due |
Type of Debt | | | Rate | | Date |
| | (in thousands) | | (%) | | |
Notes Payable – Nonaffiliated | | $ | 1,500 | | Variable | | 2008 |
Notes Payable – Nonaffiliated | | | 3,304 | | 4.47 | | 2011 |
Pollution Control Bonds | | | 41,135 | | Variable | | 2011 |
In October 2008, SWEPCo retired $113 million of 5.25% Notes Payable due in 2043. | | Principal Amount Paid | | Interest | | Due |
Type of Debt | | | Rate | | Date |
| | (in thousands) | | (%) | | |
Notes Payable – Nonaffiliated | | $ | 1,101 | | 4.47 | | 2011 |
Liquidity
In recent months, theThe financial markets have become increasingly unstable and constrainedremain volatile at both a global and domestic level. This systemic marketplace distress is impactingcould impact SWEPCo’s access to capital, liquidity and cost of capital. The uncertainties in the creditcapital markets could have significant implications on SWEPCo since it relies on continuing access to capital to fund operations and capital expenditures. Management cannot predict the length of time the credit situation will continue or its impact on SWEPCo’s operations and ability to issue debt at reasonable interest rates.
SWEPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity. SWEPCo has no debt obligations that will mature in the remainder of 2008 or 2009. To the extent refinancing is unavailable due to the challenging credit markets, SWEPCo will rely upon cash flows from operations and access to the Utility Money Pool to fund its current operations.operations and capital expenditures.
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of liquidity.
Summary Obligation Information
A summary of contractual obligations is included in the 20072008 Annual Report and has not changed significantly from year-end other than the debt issuance discussed in “Cash Flow” and “Financing Activity” above.year-end.
Significant Factors
Litigation and Regulatory Activity
In the ordinary course of business, SWEPCo is involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, management cannot state what the eventual outcome of these proceedings 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 which have a probable likelihood of loss andif the loss amount can be estimated. For details on regulatory proceedings and pending litigation, see Note 4 – Rate Matters and Note 6 – Commitments, Guarantees and Contingencies in the 20072008 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies in the “Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries”. section. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for additional discussion of relevant factors.
Critical Accounting Estimates
See the “Critical Accounting Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 20072008 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, pension and other postretirement benefits and the impact of new accounting pronouncements.
Adoption of New Accounting Pronouncements
See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section for a discussion of adoption of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
Market Risks
Risk management assets and liabilities are managed by AEPSC as agent. The related risk management policies and procedures are instituted and administered by AEPSC. See complete discussion within AEP’s “Quantitative and Qualitative Disclosures About Risk Management Activities” section. The following tables provide information about AEP’s risk management activities’ effect on SWEPCo.
MTM Risk Management Contract Net Assets
The following two tables summarize the various mark-to-market (MTM) positions included in SWEPCo’s Condensed Consolidated Balance Sheet as of September 30, 2008March 31, 2009 and the reasons for changes in total MTM value as compared to December 31, 2007.2008.
Reconciliation of MTM Risk Management Contracts to
Condensed Consolidated Balance Sheet
As of September 30, 2008March 31, 2009
(in thousands)
| | MTM Risk Management Contracts | | | Cash Flow & Fair Value Hedges | | | DETM Assignment (a) | | | Collateral Deposits | | | Total | |
Current Assets | | $ | 30,804 | | | $ | - | | | $ | - | | | $ | (528 | ) | | $ | 30,276 | |
Noncurrent Assets | | | 3,561 | | | | - | | | | - | | | | (60 | ) | | | 3,501 | |
Total MTM Derivative Contract Assets | | | 34,365 | | | | - | | | | - | | | | (588 | ) | | | 33,777 | |
| | | | | | | | | | | | | | | | | | | | |
Current Liabilities | | | (31,197 | ) | | | (90 | ) | | | (130 | ) | | | 60 | | | | (31,357 | ) |
Noncurrent Liabilities | | | (2,406 | ) | | | (93 | ) | | | (132 | ) | | | 9 | | | | (2,622 | ) |
Total MTM Derivative Contract Liabilities | | | (33,603 | ) | | | (183 | ) | | | (262 | ) | | | 69 | | | | (33,979 | ) |
| | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 762 | | | $ | (183 | ) | | $ | (262 | ) | | $ | (519 | ) | | $ | (202 | ) |
| | MTM Risk Management Contracts | | | Cash Flow Hedge Contracts | | | DETM Assignment (a) | | | Collateral Deposits | | | Total | |
Current Assets | | $ | 10,187 | | | $ | - | | | $ | - | | | $ | - | | | $ | 10,187 | |
Noncurrent Assets | | | 919 | | | | 1 | | | | - | | | | - | | | | 920 | |
Total MTM Derivative Contract Assets | | | 11,106 | | | | 1 | | | | - | | | | - | | | | 11,107 | |
| | | | | | | | | | | | | | | | | | | | |
Current Liabilities | | | (7,572 | ) | | | (331 | ) | | | (118 | ) | | | 456 | | | | (7,565 | ) |
Noncurrent Liabilities | | | (448 | ) | | | - | | | | (80 | ) | | | - | | | | (528 | ) |
Total MTM Derivative Contract Liabilities | | | (8,020 | ) | | | (331 | ) | | | (198 | ) | | | 456 | | | | (8,093 | ) |
| | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 3,086 | | | $ | (330 | ) | | $ | (198 | ) | | $ | 456 | | | $ | 3,014 | |
(a) | See “Natural Gas Contracts with DETM” section of Note 1615 of the 20072008 Annual Report. |
MTM Risk Management Contract Net Assets (Liabilities)
NineThree Months Ended September 30, 2008March 31, 2009
(in thousands)
Total MTM Risk Management Contract Net Assets at December 31, 2007 | | $ | 8,131 | |
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | | | (8,169 | ) |
Fair Value of New Contracts at Inception When Entered During the Period (a) | | | - | |
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period | | | - | |
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b) | | | 103 | |
Changes in Fair Value Due to Market Fluctuations During the Period (c) | | | 106 | |
Changes in Fair Value Allocated to Regulated Jurisdictions (d) | | | 591 | |
Total MTM Risk Management Contract Net Assets | | | 762 | |
Net Cash Flow & Fair Value Hedge Contracts | | | (183 | ) |
DETM Assignment (e) | | | (262 | ) |
Collateral Deposits | | | (519 | ) |
Ending Net Risk Management Assets (Liabilities) at September 30, 2008 | | $ | (202 | ) |
Total MTM Risk Management Contract Net Assets at December 31, 2008 | | $ | 2,643 | |
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | | | 263 | |
Fair Value of New Contracts at Inception When Entered During the Period (a) | | | - | |
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period | | | - | |
Change in Fair Value Due to Valuation Methodology Changes on Forward Contracts | | | - | |
Changes in Fair Value Due to Market Fluctuations During the Period (b) | | | 85 | |
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | | | 95 | |
Total MTM Risk Management Contract Net Assets | | | 3,086 | |
Cash Flow Hedge Contracts | | | (330 | ) |
DETM Assignment (d) | | | (198 | ) |
Collateral Deposits | | | 456 | |
Ending Net Risk Management Assets at March 31, 2009 | | $ | 3,014 | |
(a) | Reflects fair value on long-term contracts which are typically with customers that seek fixed pricing to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term. A significant portion of the total volumetric position has been economically hedged. |
(b) | Represents the impact of applying AEP’s credit risk when measuring the fair value of derivative liabilities according to SFAS 157. |
(c) | Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc. |
(d)(c) | “Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities.liabilities/assets. |
(e)(d) | See “Natural Gas Contracts with DETM” section of Note 1615 of the 20072008 Annual Report. |
Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets
The following table presents the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate cash:
Maturity and Source of Fair Value of MTM
Risk Management Contract Net Assets
Fair Value of Contracts as of September 30, 2008March 31, 2009
(in thousands)
| | Remainder 2008 | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | After 2012 | | | Total | |
Level 1 (a) | | $ | 372 | | | $ | (294 | ) | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | 78 | |
Level 2 (b) | | | 10 | | | | 1,467 | | | | 757 | | | | (122 | ) | | | - | | | | - | | | | 2,112 | |
Level 3 (c) | | | (1,429 | ) | | | - | | | | 1 | | | | - | | | | - | | | | - | | | | (1,428 | ) |
Total | | $ | (1,047 | ) | | $ | 1,173 | | | $ | 758 | | | $ | (122 | ) | | $ | - | | | $ | - | | | $ | 762 | |
| | Remainder 2009 | | | 2010 | | | 2011 | | | 2012 | | | 2013 | | | After 2013 | | | Total | |
Level 1 (a) | | $ | (518 | ) | | $ | (1 | ) | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | (519 | ) |
Level 2 (b) | | | 2,340 | | | | 1,688 | | | | (412 | ) | | | (13 | ) | | | - | | | | - | | | | 3,603 | |
Level 3 (c) | | | - | | | | 2 | | | | - | | | | - | | | | - | | | | - | | | | 2 | |
Total | | $ | 1,822 | | | $ | 1,689 | | | $ | (412 | ) | | $ | (13 | ) | | $ | - | | | $ | - | | | $ | 3,086 | |
(a) | Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 1 inputs primarily consist of exchange traded contracts that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis. |
(b) | Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in Level 1 and OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market. |
(c) | Level 3 inputs are unobservable inputs for the asset or liability. Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions. |
Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed Consolidated Balance Sheet
Management uses interest rate derivative transactions to manage interest rate risk related to anticipated borrowings of fixed-rate debt. Management does not hedge all interest rate risk.
Management uses foreign currency derivatives to lock in prices on certain forecasted transactions denominated in foreign currencies where deemed necessary, and designates qualifying instruments as cash flow hedges. Management does not hedge all foreign currency exposure.
The following table provides the detail on designated, effective cash flow hedges included in AOCI on SWEPCo’s Condensed Consolidated Balance Sheets and the reasons for the changes from December 31, 2007 to September 30, 2008. Only contracts designated as cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and included in the previous risk management tables. All amounts are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity
Nine Months Ended September 30, 2008
(in thousands)
| | Interest Rate | | | Foreign Currency | | | Total | |
Beginning Balance in AOCI December 31, 2007 | | $ | (6,650 | ) | | $ | 629 | | | $ | (6,021 | ) |
Changes in Fair Value | | | - | | | | (204 | ) | | | (204 | ) |
Reclassifications from AOCI for Cash Flow Hedges Settled | | | 621 | | | | (544 | ) | | | 77 | |
Ending Balance in AOCI September 30, 2008 | | $ | (6,029 | ) | | $ | (119 | ) | | $ | (6,148 | ) |
The portion of cash flow hedges in AOCI expected to be reclassified to earnings during the next twelve months is an $829 thousand loss.
Credit Risk
Counterparty credit quality and exposure is generally consistent with that of AEP.
See Note 7 for further information regarding MTM risk management contracts, cash flow hedging, accumulated other comprehensive income, credit risk and collateral triggering events.
VaR Associated with Risk Management Contracts
Management uses a risk measurement model, which calculates Value at Risk (VaR) to measure commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at September 30, 2008,March 31, 2009, a near term typical change in commodity prices is not expected to have a material effect on SWEPCo’s net income, cash flows or financial condition.
The following table shows the end, high, average, and low market risk as measured by VaR for the periods indicated:
Nine Months Ended September 30, 2008 | | | | | Twelve Months Ended December 31, 2007 |
(in thousands) | | | | | (in thousands) |
End | | High | | Average | | Low | | | | | End | | High | | Average | | Low |
$101 | | $220 | | $64 | | $11 | | | | | $17 | | $245 | | $75 | | $7 |
Three Months Ended | | | | | Twelve Months Ended |
March 31, 2009 | | | | | December 31, 2008 |
(in thousands) | | | | | (in thousands) |
End | | High | | Average | | Low | | | | | End | | High | | Average | | Low |
$23 | | $49 | | $20 | | $6 | | | | | $8 | | $220 | | $62 | | $8 |
Management back-tests its VaR results against performance due to actual price moves. Based on the assumed 95% confidence interval, the performance due to actual price moves would be expected to exceed the VaR at least once every 20 trading days. Management’s backtesting results show that its actual performance exceeded VaR far fewer than once every 20 trading days. As a result, management believes SWEPCo’s VaR calculation is conservative.
As SWEPCo’s VaR calculation captures recent price moves, management also performs regular stress testing of the portfolio to understand SWEPCo’s exposure to extreme price moves. Management employs a historically-basedhistorical-based method whereby the current portfolio is subjected to actual, observed price moves from the last three years in order to ascertain which historical price moves translatetranslated into the largest potential mark-to-marketMTM loss. Management then researches the underlying positions, price moves and market events that created the most significant exposure.
Interest Rate Risk
Management utilizes an Earnings at Risk (EaR) model to measure interest rate market risk exposure. EaR statistically quantifies the extent to which SWEPCo’s interest expense could vary over the next twelve months and gives a probabilistic estimate of different levels of interest expense. The resulting EaR is interpreted as the dollar amount by which actual interest expense for the next twelve months could exceed expected interest expense with a one-in-twenty chance of occurrence. The primary drivers of EaR are from the existing floating rate debt (including short-term debt) as well as long-term debt issuances in the next twelve months. The estimated EaR on SWEPCo’s debt portfolio was $1.9$3 million.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
For the Three and Nine Months Ended September 30,March 31, 2009 and 2008 and 2007
(in thousands)
(Unaudited)
| | Three Months Ended | | | Nine Months Ended | | |
| | 2008 | | | 2007 | | | 2008 | | | 2007 | | | 2009 | | | 2008 | |
REVENUES | | | | | | | | | | | | | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 500,484 | | | $ | 445,169 | | | $ | 1,232,017 | | | $ | 1,101,703 | �� | | $ | 302,383 | | | $ | 313,913 | |
Sales to AEP Affiliates | | | 11,508 | | | | 2,839 | | | | 42,692 | | | | 35,491 | | | | 8,344 | | | | 13,592 | |
Lignite Revenues – Nonaffiliated | | | | 10,720 | | | | 11,988 | |
Other | | | 471 | | | | 502 | | | | 1,164 | | | | 1,437 | | | | 355 | | | | 300 | |
TOTAL | | | 512,463 | | | | 448,510 | | | | 1,275,873 | | | | 1,138,631 | | | | 321,802 | | | | 339,793 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
EXPENSES | | | | | | | | | | | | | | | | | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 197,474 | | | | 141,837 | | | | 462,282 | | | | 379,818 | | | | 126,315 | | | | 117,661 | |
Purchased Electricity for Resale | | | 50,449 | | | | 73,438 | | | | 145,097 | | | | 182,806 | | | | 24,397 | | | | 40,270 | |
Purchased Electricity from AEP Affiliates | | | 36,170 | | | | 22,282 | | | | 108,542 | | | | 61,284 | | | | 13,010 | | | | 20,440 | |
Other Operation | | | 64,377 | | | | 59,759 | | | | 186,713 | | | | 163,746 | | | | 54,204 | | | | 63,579 | |
Maintenance | | | 33,694 | | | | 23,205 | | | | 88,854 | | | | 79,265 | | | | 26,702 | | | | 27,468 | |
Depreciation and Amortization | | | 35,842 | | | | 34,605 | | | | 108,875 | | | | 103,395 | | | | 36,792 | | | | 36,136 | |
Taxes Other Than Income Taxes | | | 12,623 | | | | 16,767 | | | | 45,747 | | | | 50,298 | | | | 15,389 | | | | 17,419 | |
TOTAL | | | 430,629 | | | | 371,893 | | | | 1,146,110 | | | | 1,020,612 | | | | 296,809 | | | | 322,973 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 81,834 | | | | 76,617 | | | | 129,763 | | | | 118,019 | | | | 24,993 | | | | 16,820 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | | | | |
Interest Income | | | 5,417 | | | | 518 | | | | 7,834 | | | | 1,999 | | | | 454 | | | | 877 | |
Allowance for Equity Funds Used During Construction | | | 4,152 | | | | 3,681 | | | | 10,167 | | | | 7,634 | | | | 6,405 | | | | 3,063 | |
Interest Expense | | | (22,659 | ) | | | (15,966 | ) | | | (57,071 | ) | | | (48,691 | ) | | | (16,299 | ) | | | (17,142 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE AND MINORITY INTEREST EXPENSE | | | 68,744 | | | | 64,850 | | | | 90,693 | | | | 78,961 | | |
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS | | | | 15,553 | | | | 3,618 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Income Tax Expense | | | 20,353 | | | | 19,811 | | | | 21,717 | | | | 20,879 | | |
Minority Interest Expense | | | 976 | | | | 919 | | | | 2,870 | | | | 2,733 | | |
Income Tax Expense (Credit) | | | | 3,853 | | | | (1,987 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
NET INCOME | | | 47,415 | | | | 44,120 | | | | 66,106 | | | | 55,349 | | | | 11,700 | | | | 5,605 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Preferred Stock Dividend Requirements | | | 58 | | | | 58 | | | | 172 | | | | 172 | | |
Less: Net Income Attributable to Noncontrolling Interest | | | | 1,137 | | | | 995 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
EARNINGS APPLICABLE TO COMMON STOCK | | $ | 47,357 | | | $ | 44,062 | | | $ | 65,934 | | | $ | 55,177 | | |
NET INCOME ATTRIBUTABLE TO SWEPCo SHAREHOLDERS | | | | 10,563 | | | | 4,610 | |
| | | | | | | | | |
Less: Preferred Stock Dividend Requirements | | | | 57 | | | | 57 | |
| | | | | | | | | |
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER | | | $ | 10,506 | | | $ | 4,553 | |
The common stock of SWEPCo is wholly-owned by AEP. |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER’S
EQUITY AND COMPREHENSIVE INCOME (LOSS)
For the NineThree Months Ended September 30,March 31, 2009 and 2008 and 2007
(in thousands)
(Unaudited)
| | Common Stock | | | Paid-in Capital | | | Retained Earnings | | | Accumulated Other Comprehensive Income (Loss) | | | Total | |
DECEMBER 31, 2006 | | $ | 135,660 | | | $ | 245,003 | | | $ | 459,338 | | | $ | (18,799 | ) | | $ | 821,202 | |
| | | | | | | | | | | | | | | | | | | | |
FIN 48 Adoption, Net of Tax | | | | | | | | | | | (1,642 | ) | | | | | | | (1,642 | ) |
Capital Contribution from Parent | | | | | | | 55,000 | | | | | | | | | | | | 55,000 | |
Preferred Stock Dividends | | | | | | | | | | | (172 | ) | | | | | | | (172 | ) |
TOTAL | | | | | | | | | | | | | | | | | | | 874,388 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $90 | | | | | | | | | | | | | | | 168 | | | | 168 | |
NET INCOME | | | | | | | | | | | 55,349 | | | | | | | | 55,349 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 55,517 | |
| | | | | | | | | | | | | | | | | | | | |
SEPTEMBER 30, 2007 | | $ | 135,660 | | | $ | 300,003 | | | $ | 512,873 | | | $ | (18,631 | ) | | $ | 929,905 | |
| | | | | | | | | | | | | | | | | | | | |
DECEMBER 31, 2007 | | $ | 135,660 | | | $ | 330,003 | | | $ | 523,731 | | | $ | (16,439 | ) | | $ | 972,955 | |
| | | | | | | | | | | | | | | | | | | | |
EITF 06-10 Adoption, Net of Tax of $622 | | | | | | | | | | | (1,156 | ) | | | | | | | (1,156 | ) |
SFAS 157 Adoption, Net of Tax of $6 | | | | | | | | | | | 10 | | | | | | | | 10 | |
Capital Contribution from Parent | | | | | | | 100,000 | | | | | | | | | | | | 100,000 | |
Preferred Stock Dividends | | | | | | | | | | | (172 | ) | | | | | | | (172 | ) |
TOTAL | | | | | | | | | | | | | | | | | | | 1,071,637 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $69 | | | | | | | | | | | | | | | (127 | ) | | | (127 | ) |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $380 | | | | | | | | | | | | | | | 706 | | | | 706 | |
NET INCOME | | | | | | | | | | | 66,106 | | | | | | | | 66,106 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 66,685 | |
| | | | | | | | | | | | | | | | | | | | |
SEPTEMBER 30, 2008 | | $ | 135,660 | | | $ | 430,003 | | | $ | 588,519 | | | $ | (15,860 | ) | | $ | 1,138,322 | |
| | SWEPCo Common Shareholder | | | | | | | |
| | Common Stock | | | Paid-in Capital | | | Retained Earnings | | | Accumulated Other Comprehensive Income (Loss) | | | Noncontrolling Interest | | | Total | |
| | | | | | | | | | | | | | | | | | |
DECEMBER 31, 2007 | | $ | 135,660 | | | $ | 330,003 | | | $ | 523,731 | | | $ | (16,439 | ) | | $ | 1,687 | | | $ | 974,642 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
EITF 06-10 Adoption, Net of Tax of $622 | | | | | | | | | | | (1,156 | ) | | | | | | | | | | | (1,156 | ) |
SFAS 157 Adoption, Net of Tax of $6 | | | | | | | | | | | 10 | | | | | | | | | | | | 10 | |
Capital Contribution from Parent | | | | | | | 50,000 | | | | | | | | | | | | | | | | 50,000 | |
Common Stock Dividends – Nonaffiliated | | | | | | | | | | | | | | | | | | | (949 | ) | | | (949 | ) |
Preferred Stock Dividends | | | | | | | | | | | (57 | ) | | | | | | | | | | | (57 | ) |
TOTAL | | | | | | | | | | | | | | | | | | | | | | | 1,022,490 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $143 | | | | | | | | | | | | | | | (269 | ) | | | 4 | | | | (265 | ) |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $127 | | | | | | | | | | | | | | | 235 | | | | | | | | 235 | |
NET INCOME | | | | | | | | | | | 4,610 | | | | | | | | 995 | | | | 5,605 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | 5,575 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
MARCH 31, 2008 | | $ | 135,660 | | | $ | 380,003 | | | $ | 527,138 | | | $ | (16,473 | ) | | $ | 1,737 | | | $ | 1,028,065 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
DECEMBER 31, 2008 | | $ | 135,660 | | | $ | 530,003 | | | $ | 615,110 | | | $ | (32,120 | ) | | $ | 276 | | | $ | 1,248,929 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Capital Contribution from Parent | | | | | | | 17,500 | | | | | | | | | | | | | | | | 17,500 | |
Common Stock Dividends – Nonaffiliated | | | | | | | | | | | | | | | | | | | (1,115 | ) | | | (1,115 | ) |
Preferred Stock Dividends | | | | | | | | | | | (57 | ) | | | | | | | | | | | (57 | ) |
Other | | | | | | | 2,476 | | | | (2,476 | ) | | | | | | | | | | | - | |
TOTAL | | | | | | | | | | | | | | | | | | | | | | | 1,265,257 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $51 | | | | | | | | | | | | | | | 95 | | | | | | | | 95 | |
Amortization of Pension and OPEB Deferred Costs, Net of Tax of $243 | | | | | | | | | | | | | | | 451 | | | | | | | | 451 | |
NET INCOME | | | | | | | | | | | 10,563 | | | | | | | | 1,137 | | | | 11,700 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | 12,246 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
MARCH 31, 2009 | | $ | 135,660 | | | $ | 549,979 | | | $ | 623,140 | | | $ | (31,574 | ) | | $ | 298 | | | $ | 1,277,503 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
September 30, 2008March 31, 2009 and December 31, 20072008
(in thousands)
(Unaudited)
| | 2008 | | | 2007 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 2,752 | | | $ | 1,742 | |
Advances to Affiliates | | | 195,628 | | | | - | |
Accounts Receivable: | | | | | | | | |
Customers | | | 32,619 | | | | 91,379 | |
Affiliated Companies | | | 42,876 | | | | 33,196 | |
Miscellaneous | | | 12,781 | | | | 10,544 | |
Allowance for Uncollectible Accounts | | | (135 | ) | | | (143 | ) |
Total Accounts Receivable | | | 88,141 | | | | 134,976 | |
Fuel | | | 89,408 | | | | 75,662 | |
Materials and Supplies | | | 51,565 | | | | 48,673 | |
Risk Management Assets | | | 30,276 | | | | 39,850 | |
Regulatory Asset for Under-Recovered Fuel Costs | | | 81,907 | | | | 5,859 | |
Margin Deposits | | | 600 | | | | 10,650 | |
Prepayments and Other | | | 38,406 | | | | 28,147 | |
TOTAL | | | 578,683 | | | | 345,559 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Production | | | 1,756,486 | | | | 1,743,198 | |
Transmission | | | 771,747 | | | | 737,975 | |
Distribution | | | 1,364,596 | | | | 1,312,746 | |
Other | | | 698,764 | | | | 631,765 | |
Construction Work in Progress | | | 735,226 | | | | 451,228 | |
Total | | | 5,326,819 | | | | 4,876,912 | |
Accumulated Depreciation and Amortization | | | 1,996,531 | | | | 1,939,044 | |
TOTAL - NET | | | 3,330,288 | | | | 2,937,868 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 120,858 | | | | 133,617 | |
Long-term Risk Management Assets | | | 3,501 | | | | 4,073 | |
Deferred Charges and Other | | | 93,126 | | | | 67,269 | |
TOTAL | | | 217,485 | | | | 204,959 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 4,126,456 | | | $ | 3,488,386 | |
| | 2009 | | | 2008 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 1,737 | | | $ | 1,910 | |
Advances to Affiliates | | | 37,649 | | | | - | |
Accounts Receivable: | | | | | | | | |
Customers | | | 53,346 | | | | 53,506 | |
Affiliated Companies | | | 29,914 | | | | 121,928 | |
Miscellaneous | | | 9,590 | | | | 12,052 | |
Allowance for Uncollectible Accounts | | | (145 | ) | | | (135 | ) |
Total Accounts Receivable | | | 92,705 | | | | 187,351 | |
Fuel | | | 103,544 | | | | 100,018 | |
Materials and Supplies | | | 50,973 | | | | 49,724 | |
Risk Management Assets | | | 10,187 | | | | 8,185 | |
Regulatory Asset for Under-Recovered Fuel Costs | | | 35,495 | | | | 75,006 | |
Prepayments and Other | | | 23,420 | | | | 20,147 | |
TOTAL | | | 355,710 | | | | 442,341 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Production | | | 1,811,359 | | | | 1,808,482 | |
Transmission | | | 793,702 | | | | 786,731 | |
Distribution | | | 1,415,210 | | | | 1,400,952 | |
Other | | | 712,739 | | | | 711,260 | |
Construction Work in Progress | | | 904,837 | | | | 869,103 | |
Total | | | 5,637,847 | | | | 5,576,528 | |
Accumulated Depreciation and Amortization | | | 2,048,482 | | | | 2,014,154 | |
TOTAL - NET | | | 3,589,365 | | | | 3,562,374 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 219,245 | | | | 210,174 | |
Long-term Risk Management Assets | | | 920 | | | | 1,500 | |
Deferred Charges and Other | | | 63,328 | | | | 36,696 | |
TOTAL | | | 283,493 | | | | 248,370 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 4,228,568 | | | $ | 4,253,085 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED BALANCE SHEETS
LIABILITIES AND SHAREHOLDERS’ EQUITY
September 30, 2008March 31, 2009 and December 31, 20072008
(Unaudited)
| | 2008 | | | 2007 | |
CURRENT LIABILITIES | | (in thousands) | |
Advances from Affiliates | | $ | - | | | $ | 1,565 | |
Accounts Payable: | | | | | | | | |
General | | | 163,540 | | | | 152,305 | |
Affiliated Companies | | | 41,010 | | | | 51,767 | |
Short-term Debt – Nonaffiliated | | | 9,519 | | | | 285 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 117,809 | | | | 5,906 | |
Risk Management Liabilities | | | 31,357 | | | | 32,629 | |
Customer Deposits | | | 34,989 | | | | 37,473 | |
Accrued Taxes | | | 60,052 | | | | 26,494 | |
Regulatory Liability for Over-Recovered Fuel Costs | | | - | | | | 22,879 | |
Other | | | 94,559 | | | | 76,554 | |
TOTAL | | | 552,835 | | | | 407,857 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 1,424,395 | | | | 1,141,311 | |
Long-term Debt – Affiliated | | | 50,000 | | | | 50,000 | |
Long-term Risk Management Liabilities | | | 2,622 | | | | 3,334 | |
Deferred Income Taxes | | | 407,149 | | | | 361,806 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 331,985 | | | | 334,014 | |
Deferred Credits and Other | | | 214,153 | | | | 210,725 | |
TOTAL | | | 2,430,304 | | | | 2,101,190 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 2,983,139 | | | | 2,509,047 | |
| | | | | | | | |
Minority Interest | | | 298 | | | | 1,687 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 4,697 | | | | 4,697 | |
| | | | | | | | |
Commitments and Contingencies (Note 4) | | | | | | | | |
| | | | | | | | |
COMMON SHAREHOLDER’S EQUITY | | | | | | | | |
Common Stock – Par Value – $18 Per Share: | | | | | | | | |
Authorized – 7,600,000 Shares | | | | | | | | |
Outstanding – 7,536,640 Shares | | | 135,660 | | | | 135,660 | |
Paid-in Capital | | | 430,003 | | | | 330,003 | |
Retained Earnings | | | 588,519 | | | | 523,731 | |
Accumulated Other Comprehensive Income (Loss) | | | (15,860 | ) | | | (16,439 | ) |
TOTAL | | | 1,138,322 | | | | 972,955 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 4,126,456 | | | $ | 3,488,386 | |
| | 2009 | | | 2008 | |
CURRENT LIABILITIES | | (in thousands) | |
Advances from Affiliates | | $ | - | | | $ | 2,526 | |
Accounts Payable: | | | | | | | | |
General | | | 121,185 | | | | 133,538 | |
Affiliated Companies | | | 56,181 | | | | 51,040 | |
Short-term Debt – Nonaffiliated | | | 6,559 | | | | 7,172 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 4,406 | | | | 4,406 | |
Long-term Debt Due Within One Year – Affiliated | | | 50,000 | | | | - | |
Risk Management Liabilities | | | 7,565 | | | | 6,735 | |
Customer Deposits | | | 38,211 | | | | 35,622 | |
Accrued Taxes | | | 92,538 | | | | 33,744 | |
Accrued Interest | | | 16,487 | | | | 36,647 | |
Regulatory Liability for Over-Recovered Fuel Costs | | | 6,380 | | | | 5,162 | |
Provision for Revenue Refund | | | 26,957 | | | | 54,100 | |
Other | | | 59,117 | | | | 97,373 | |
TOTAL | | | 485,586 | | | | 468,065 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 1,422,744 | | | | 1,423,743 | |
Long-term Debt – Affiliated | | | - | | | | 50,000 | |
Long-term Risk Management Liabilities | | | 528 | | | | 516 | |
Deferred Income Taxes | | | 386,089 | | | | 403,125 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 333,386 | | | | 335,749 | |
Asset Retirement Obligations | | | 52,018 | | | | 53,433 | |
Employment Benefits and Pension Obligations | | | 123,689 | | | | 117,772 | |
Deferred Credits and Other | | | 142,328 | | | | 147,056 | |
TOTAL | | | 2,460,782 | | | | 2,531,394 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 2,946,368 | | | | 2,999,459 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 4,697 | | | | 4,697 | |
| | | | | | | | |
Commitments and Contingencies (Note 4) | | | | | | | | |
| | | | | | | | |
EQUITY | | | | | | | | |
Common Stock – Par Value – $18 Per Share: | | | | | | | | |
Authorized – 7,600,000 Shares | | | | | | | | |
Outstanding – 7,536,640 Shares | | | 135,660 | | | | 135,660 | |
Paid-in Capital | | | 549,979 | | | | 530,003 | |
Retained Earnings | | | 623,140 | | | | 615,110 | |
Accumulated Other Comprehensive Income (Loss) | | | (31,574 | ) | | | (32,120 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | | 1,277,205 | | | | 1,248,653 | |
| | | | | | | | |
Noncontrolling Interest | | | 298 | | | | 276 | |
| | | | | | | | |
TOTAL EQUITY | | | 1,277,503 | | | | 1,248,929 | |
| | | | | | | | |
TOTAL LIABILITIES AND EQUITY | | $ | 4,228,568 | | | $ | 4,253,085 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the NineThree Months Ended September 30,March 31, 2009 and 2008 and 2007
(in thousands)
(Unaudited)
| | 2009 | | | 2008 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 11,700 | | | $ | 5,605 | |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 36,792 | | | | 36,136 | |
Deferred Income Taxes | | | (27,042 | ) | | | 3,804 | |
Allowance for Equity Funds Used During Construction | | | (6,405 | ) | | | (3,063 | ) |
Mark-to-Market of Risk Management Contracts | | | (752 | ) | | | (14,231 | ) |
Deferred Property Taxes | | | (29,792 | ) | | | (29,799 | ) |
Change in Other Noncurrent Assets | | | 6,230 | | | | 6,589 | |
Change in Other Noncurrent Liabilities | | | 331 | | | | (14,680 | ) |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 94,646 | | | | 22,169 | |
Fuel, Materials and Supplies | | | (4,775 | ) | | | (1,874 | ) |
Accounts Payable | | | (2,717 | ) | | | 7,398 | |
Accrued Taxes, Net | | | 58,794 | | | | 21,279 | |
Accrued Interest | | | (20,160 | ) | | | 749 | |
Fuel Over/Under-Recovery, Net | | | 26,786 | | | | (39,888 | ) |
Other Current Assets | | | 326 | | | | 7,683 | |
Other Current Liabilities | | | (50,492 | ) | | | (11,030 | ) |
Net Cash Flows from (Used for) Operating Activities | | | 93,470 | | | | (3,153 | ) |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (169,603 | ) | | | (125,358 | ) |
Change in Other Cash Deposits | | | (954 | ) | | | (585 | ) |
Change in Advances to Affiliates, Net | | | (37,649 | ) | | | - | |
Proceeds from Sales of Assets | | | 104,824 | | | | 66 | |
Net Cash Flows Used for Investing Activities | | | (103,382 | ) | | | (125,877 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Capital Contribution from Parent | | | 17,500 | | | | 50,000 | |
Issuance of Long-term Debt – Nonaffiliated | | | (15 | ) | | | - | |
Change in Short-term Debt, Net – Nonaffiliated | | | (613 | ) | | | (285 | ) |
Change in Advances from Affiliates, Net | | | (2,526 | ) | | | 87,645 | |
Retirement of Long-term Debt – Nonaffiliated | | | (1,101 | ) | | | (1,851 | ) |
Principal Payments for Capital Lease Obligations | | | (2,334 | ) | | | (1,312 | ) |
Dividends Paid on Common Stock – Nonaffiliated | | | (1,115 | ) | | | (949 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (57 | ) | | | (57 | ) |
Net Cash Flows from Financing Activities | | | 9,739 | | | | 133,191 | |
| | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | (173 | ) | | | 4,161 | |
Cash and Cash Equivalents at Beginning of Period | | | 1,910 | | | | 1,742 | |
Cash and Cash Equivalents at End of Period | | $ | 1,737 | | | $ | 5,903 | |
| | 2008 | | | 2007 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 66,106 | | | $ | 55,349 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 108,875 | | | | 103,395 | |
Deferred Income Taxes | | | 37,162 | | | | (17,863 | ) |
Provision for Fuel Disallowance | | | - | | | | 24,074 | |
Allowance for Equity Funds Used During Construction | | | (10,167 | ) | | | (7,634 | ) |
Mark-to-Market of Risk Management Contracts | | | 7,905 | | | | 7,864 | |
Deferred Property Taxes | | | (9,315 | ) | | | (9,172 | ) |
Change in Other Noncurrent Assets | | | 9,104 | | | | 10,170 | |
Change in Other Noncurrent Liabilities | | | (17,015 | ) | | | (7,134 | ) |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 46,835 | | | | 47,992 | |
Fuel, Materials and Supplies | | | (16,665 | ) | | | (11,572 | ) |
Margin Deposits | | | 10,050 | | | | 29,986 | |
Accounts Payable | | | (34,819 | ) | | | (21,603 | ) |
Accrued Taxes, Net | | | 29,271 | | | | 25,556 | |
Fuel Over/Under-Recovery, Net | | | (98,928 | ) | | | (26,891 | ) |
Other Current Assets | | | (3,121 | ) | | | (687 | ) |
Other Current Liabilities | | | 4,972 | | | | (21,684 | ) |
Net Cash Flows from Operating Activities | | | 130,250 | | | | 180,146 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (424,092 | ) | | | (353,107 | ) |
Change in Advances to Affiliates, Net | | | (195,628 | ) | | | - | |
Other | | | 233 | | | | 106 | |
Net Cash Flows Used for Investing Activities | | | (619,487 | ) | | | (353,001 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Capital Contribution from Parent | | | 100,000 | | | | 55,000 | |
Issuance of Long-term Debt – Nonaffiliated | | | 437,113 | | | | 247,496 | |
Change in Short-term Debt, Net – Nonaffiliated | | | 9,234 | | | | 8,754 | |
Change in Advances from Affiliates, Net | | | (1,565 | ) | | | (33,096 | ) |
Retirement of Long-term Debt – Nonaffiliated | | | (45,939 | ) | | | (100,460 | ) |
Principal Payments for Capital Lease Obligations | | | (8,424 | ) | | | (5,433 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (172 | ) | | | (172 | ) |
Net Cash Flows from Financing Activities | | | 490,247 | | | | 172,089 | |
| | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 1,010 | | | | (766 | ) |
Cash and Cash Equivalents at Beginning of Period | | | 1,742 | | | | 2,618 | |
Cash and Cash Equivalents at End of Period | | $ | 2,752 | | | $ | 1,852 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 44,255 | | | $ | 44,662 | |
Net Cash Paid (Received) for Income Taxes | | | (20,835 | ) | | | 37,479 | |
Noncash Acquisitions Under Capital Leases | | | 21,807 | | | | 19,567 | |
Construction Expenditures Included in Accounts Payable at September 30, | | | 94,837 | | | | 41,978 | |
SUPPLEMENTARY INFORMATION | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 51,573 | | | $ | 14,049 | |
Net Cash Paid (Received) for Income Taxes | | | (1,117 | ) | | | 641 | |
Noncash Acquisitions Under Capital Leases | | | 1,568 | | | | 6,796 | |
Construction Expenditures Included in Accounts Payable at March 31, | | | 72,331 | | | | 63,973 | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
INDEX TO CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES
The condensed notes to SWEPCo’s condensed consolidated financial statements are combined with the condensed notes to condensed financial statements for other registrant subsidiaries. Listed below are the notes that apply to SWEPCo.
| Footnote Reference |
| |
Significant Accounting Matters | Note 1 |
New Accounting Pronouncements and Extraordinary Item | Note 2 |
Rate Matters | Note 3 |
Commitments, Guarantees and Contingencies | Note 4 |
Benefit Plans | Note 65 |
Business Segments | Note 6 |
Derivatives, Hedging and Fair Value Measurements | Note 7 |
Income Taxes | Note 8 |
Financing Activities | Note 9 |
CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES
The condensed notes to condensed financial statements that follow are a combined presentation for the Registrant Subsidiaries. The following list indicates the registrants to which the footnotes apply: |
| | |
1. | Significant Accounting Matters | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
2. | New Accounting Pronouncements and Extraordinary Item | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
3. | Rate Matters | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
4. | Commitments, Guarantees and Contingencies | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
5. | Acquisition | CSPCo |
6. | Benefit Plans | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
7.6. | Business Segments | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
7. | Derivatives, Hedging and Fair Value Measurements | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
8. | Income Taxes | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
9. | Financing Activities | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
1. | SIGNIFICANT ACCOUNTING MATTERS |
General
The accompanying unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all the information and footnotes required by GAAP for complete annual financial statements.
In the opinion of management, the unaudited interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. The net income for the three and nine months ended September 30, 2008 areMarch 31, 2009 is not necessarily indicative of results that may be expected for the year ending December 31, 2008.2009. The accompanying condensed financial statements are unaudited and should be read in conjunction with the audited 20072008 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 20072008 as filed with the SEC on February 28, 2008.27, 2009.
ReclassificationsVariable Interest Entities
Certain prior periodFIN 46R is a consolidation model that considers risk absorption of a variable interest entity (VIE), also referred to as variability. Entities are required to consolidate a VIE when it is determined that they are the primary beneficiary of that VIE, as defined by FIN 46R. In determining whether they are the primary beneficiary of a VIE, each Registrant Subsidiary considers factors such as equity at risk, the amount of the VIE’s variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE and other factors. Management believes that significant assumptions and judgments were applied consistently and that there are no other reasonable judgments or assumptions that would result in a different conclusion. In addition, the Registrant Subsidiaries have not provided financial statement itemsor other support to any VIE that was not previously contractually required.
SWEPCo is the primary beneficiary of Sabine and DHLC. OPCo is the primary beneficiary of JMG. APCo, CSPCo, I&M, OPCo, PSO and SWEPCo each hold a significant variable interest in AEPSC. I&M and CSPCo each hold a significant variable interest in AEGCo.
Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have been reclassifiedno recourse to conformany AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to current period presentation.pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee which is included in Fuel and Other Consumables Used for Electric Generation on SWEPCo’s Condensed Consolidated Statements of Income. Based on these facts, management has concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the three months ended March 31, 2009 and 2008 were $35 million and $20 million, respectively. See “FSP FIN 39-1 Amendmentthe tables below for the classification of FASB Interpretation No. 39”Sabine’s assets and liabilities on SWEPCo’s Condensed Consolidated Balance Sheets.
DHLC is a wholly-owned subsidiary of SWEPCo. DHLC is a mining operator who sells 50% of the lignite produced to SWEPCo and 50% to Cleco Corporation, a nonaffiliated company. SWEPCo and Cleco Corporation share half of the executive board seats, with equal voting rights and each entity guarantees a 50% share of DHLC’s debt. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. Based on the structure and equity ownership, management has concluded that SWEPCo is the primary beneficiary and is required to consolidate DHLC. SWEPCo’s total billings from DHLC for the three months ended March 31, 2009 and 2008 were $11 million and $12 million, respectively. These billings are included in Fuel and Other Consumables Used for Electric Generation on SWEPCo’s Condensed Consolidated Statements of Income. See the tables below for the classification of DHLC assets and liabilities on SWEPCo’s Condensed Consolidated Balance Sheets.
The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that would be eliminated upon consolidation.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
March 31, 2009
(in millions)
| | Sabine | | | DHLC | |
ASSETS | | | | | | |
Current Assets | | $ | 34 | | | $ | 18 | |
Net Property, Plant and Equipment | | | 122 | | | | 32 | |
Other Noncurrent Assets | | | 30 | | | | 11 | |
Total Assets | | $ | 186 | | | $ | 61 | |
| | | | | | | | |
LIABILITIES AND EQUITY | | | | | | | | |
Current Liabilities | | $ | 34 | | | $ | 12 | |
Noncurrent Liabilities | | | 152 | | | | 45 | |
Equity | | | - | | | | 4 | |
Total Liabilities and Equity | | $ | 186 | | | $ | 61 | |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITIES
December 31, 2008
(in millions)
| | Sabine | | | DHLC | |
ASSETS | | | | | | |
Current Assets | | $ | 33 | | | $ | 22 | |
Net Property, Plant and Equipment | | | 117 | | | | 33 | |
Other Noncurrent Assets | | | 24 | | | | 11 | |
Total Assets | | $ | 174 | | | $ | 66 | |
| | | | | | | | |
LIABILITIES AND EQUITY | | | | | | | | |
Current Liabilities | | $ | 32 | | | $ | 18 | |
Noncurrent Liabilities | | | 142 | | | | 44 | |
Equity | | | - | | | | 4 | |
Total Liabilities and Equity | | $ | 174 | | | $ | 66 | |
OPCo has a lease agreement with JMG to finance OPCo’s FGD system installed on OPCo’s Gavin Plant. The PUCO approved the original lease agreement between OPCo and JMG. JMG has a capital structure of substantially all debt from pollution control bonds and other debt. JMG owns and leases the FGD to OPCo. JMG is considered a single-lessee leasing arrangement with only one asset. OPCo’s lease payments are the only form of repayment associated with JMG’s debt obligations even though OPCo does not guarantee JMG’s debt. The creditors of JMG have no recourse to any AEP entity other than OPCo for the lease payment. OPCo does not have any ownership interest in JMG. Based on the structure of the entity, management has concluded that OPCo is the primary beneficiary and is required to consolidate JMG. OPCo’s total billings from JMG for the three months ended March 31, 2009 and 2008 were $17 million and $12 million, respectively. See the tables below for the classification of JMG’s assets and liabilities on OPCo’s Condensed Consolidated Balance Sheets.
The balances below represent the assets and liabilities of the VIE that are consolidated. These balances include intercompany transactions that would be eliminated upon consolidation.
OHIO POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITY
March 31, 2009
(in millions)
| | JMG | |
ASSETS | | | |
Current Assets | | $ | 13 | |
Net Property, Plant and Equipment | | | 417 | |
Other Noncurrent Assets | | | 1 | |
Total Assets | | $ | 431 | |
| | | | |
LIABILITIES AND EQUITY | | | | |
Current Liabilities | | $ | 156 | |
Noncurrent Liabilities | | | 257 | |
Equity | | | 18 | |
Total Liabilities and Equity | | $ | 431 | |
OHIO POWER COMPANY CONSOLIDATED
VARIABLE INTEREST ENTITY
December 31, 2008
(in millions)
| | JMG | |
ASSETS | | | |
Current Assets | | $ | 11 | |
Net Property, Plant and Equipment | | | 423 | |
Other Noncurrent Assets | | | 1 | |
Total Assets | | $ | 435 | |
| | | | |
LIABILITIES AND EQUITY | | | | |
Current Liabilities | | $ | 161 | |
Noncurrent Liabilities | | | 257 | |
Equity | | | 17 | |
Total Liabilities and Equity | | $ | 435 | |
AEPSC provides certain managerial and professional services to AEP’s subsidiaries. AEP is the sole equity owner of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. No AEP subsidiary has provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations by cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP’s subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. All Registrant Subsidiaries are considered to have a significant interest in the variability in AEPSC due to their activity in AEPSC’s cost reimbursement structure. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.
Total AEPSC billings to the Registrant Subsidiaries were as follows:
| | Three Months Ended March 31, | |
| | 2009 | | | 2008 | |
Company | | (in millions) | |
APCo | | $ | 50 | | | $ | 62 | |
CSPCo | | | 29 | | | | 32 | |
I&M | | | 29 | | | | 40 | |
OPCo | | | 41 | | | | 51 | |
PSO | | | 21 | | | | 30 | |
SWEPCo | | | 29 | | | | 34 | |
The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows:
| | March 31, 2009 | | | December 31, 2008 | |
| | As Reported in the Balance Sheet | | | Maximum Exposure | | | As Reported in the Balance Sheet | | | Maximum Exposure | |
| | (in millions) | |
APCo | | $ | 14 | | | $ | 14 | | | $ | 27 | | | $ | 27 | |
CSPCo | | | 9 | | | | 9 | | | | 15 | | | | 15 | |
I&M | | | 8 | | | | 8 | | | | 14 | | | | 14 | |
OPCo | | | 11 | | | | 11 | | | | 21 | | | | 21 | |
PSO | | | 6 | | | | 6 | | | | 10 | | | | 10 | |
SWEPCo | | | 8 | | | | 8 | | | | 14 | | | | 14 | |
AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant Unit 1, leases a 50% interest in Rockport Plant Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. In May 2007, AEGCo began leasing the Lawrenceburg Generating Station to CSPCo. AEP guarantees all the debt obligations of AEGCo. I&M and CSPCo are considered to have a significant interest in AEGCo due to these transactions. I&M and CSPCo are exposed to losses to the extent they cannot recover the costs of AEGCo through their normal business operations. Due to the nature of the AEP Power Pool, there is a sharing of the cost of Rockport and Lawrenceburg Plants such that no member of the AEP Power Pool is the primary beneficiary of AEGCo’s Rockport or Lawrenceburg Plants. In the event AEGCo would require financing or other support outside the billings to I&M, CSPCo and KPCo, this financing would be provided by AEP. For additional information regarding AEGCo’s lease, see “Rockport Lease” section of Note 2 for discussion13 in the 2008 Annual Report.
Total billings from AEGCo were as follows:
| Three Months Ended March 31, | |
| 2009 | | 2008 | |
| (in millions) | |
CSPCo | | $ | 17 | | | $ | 24 | |
I&M | | | 63 | | | | 59 | |
The carrying amount and classification of changesvariable interest in netting certain balance sheetAEGCo’s accounts payable are as follows:
| March 31, 2009 | | December 31, 2008 | |
| As Reported in the Consolidated Balance Sheet | | Maximum Exposure | | As Reported in the Consolidated Balance Sheet | | Maximum Exposure | |
| (in millions) | |
CSPCo | | $ | 6 | | | $ | 6 | | | $ | 5 | | | $ | 5 | |
I&M | | | 21 | | | | 21 | | | | 23 | | | | 23 | |
Revenue Recognition – Traditional Electricity Supply and Demand
Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrant Subsidiaries recognize the revenues on their statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. These reclassifications had no impact
Most of the power produced at the generation plants of the AEP East companies is sold to PJM, the RTO operating in the east service territory. The AEP East companies then purchase power from PJM to supply their customers. Generally, these power sales and purchases are reported on a net basis as revenues on the Registrant Subsidiaries’ previously reported net income or changesAEP East companies’ statements of income. However, in shareholders’ equity.the first quarter of 2009, there were times when the AEP East companies were purchasers of power from PJM to serve retail load. These purchases were recorded gross as Purchased Electricity for Resale on the AEP East companies’ statements of income. Other RTOs in which the AEP East companies operate do not function in the same manner as PJM. They function as balancing organizations and not as exchanges.
Physical energy purchases, including those from RTOs, that are identified as non-trading, are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income.
CSPCo and OPCo Revised Depreciation Rates
Effective January 1, 2009, CSPCo and OPCo revised book depreciation rates for generating plants consistent with a recently completed depreciation study. OPCo’s overall higher depreciation rates primarily related to shortened depreciable lives for certain OPCo generating facilities. The impact of the change in depreciation rates was an increase in OPCo’s depreciation expense of $17 million and a decrease in CSPCo’s depreciation expense of $4 million when comparing the three months ended March 31, 2009 and 2008.
Acquisition – Oxbow Mine Lignite – Affecting SWEPCo
In April 2009, SWEPCo and its wholly-owned lignite mining subsidiary, Dolet Hills Mining Company, LLC (DHLC), agreed to purchase 50% of the Oxbow Mine lignite reserves and 100% of all associated mining equipment and assets from The North American Coal Corporation and its affiliates, Red River Mining Company and Oxbow Property Company, LLC for $42 million. Cleco Power LLC (Cleco), will acquire the remaining 50% of the lignite reserves. Consummation of the transaction is subject to regulatory approval by the LPSC and the APSC and the transfer of other regulatory instruments. If approved, DHLC will acquire and own the Oxbow Mine mining equipment and related assets and it will operate the Oxbow Mine. The Oxbow Mine is located near Coushatta, Louisiana and will be used as one of the fuel sources for SWEPCo’s and Cleco’s jointly-owned Dolet Hills Generating Station.
2. | NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEM |
NEW ACCOUNTING PRONOUNCEMENTS
Upon issuance of final pronouncements, management thoroughly reviews the new accounting literature to determine theits relevance, if any, to the Registrant Subsidiaries’ business. The following represents a summary of newfinal pronouncements issued or implemented in 20082009 and standards issued but not implemented that management has determined relate to the Registrant Subsidiaries’ operations.
Pronouncements Adopted During the First Quarter of 2009
The following standards were effective during the first quarter of 2009. Consequently, the financial statements and footnotes reflect their impact.
SFAS 141 (revised 2007) “Business Combinations” (SFAS 141R)
In December 2007, the FASB issued SFAS 141R, improving financial reporting about business combinations and their effects. It establishesestablished how the acquiring entity recognizes and measures the identifiable assets acquired, liabilities assumed, goodwill acquired, any gain on bargain purchases and any noncontrolling interest in the acquired entity. SFAS 141R no longer allows acquisition-related costs to be included in the cost of the business combination, but rather expensed in the periods they are incurred, with the exception of the costs to issue debt or equity securities which shall be recognized in accordance with other applicable GAAP. SFAS 141RThe standard requires disclosure of information for a business combination that occurs during the accounting period or prior to the issuance of the financial statements for the accounting period. SFAS 141R can affect tax positions on previous acquisitions. The Registrant Subsidiaries do not have any such tax positions that result in adjustments.
In April 2009, the FASB issued FSP SFAS 141(R)-1 “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies.” The standard clarifies accounting and disclosure for contingencies arising in business combinations. It was effective January 1, 2009.
The Registrant Subsidiaries adopted SFAS 141R, including the FSP, effective January 1, 2009. It is effective prospectively for business combinations with an acquisition date on or after the beginning of the first annual reporting period after December 15, 2008. Early adoption is prohibited.January 1, 2009. The Registrant Subsidiaries will adopt SFAS 141R effective January 1, 2009 and apply it to any future business combinations on or after that date.combinations.
SFAS 157 “Fair Value Measurements” (SFAS 157)
In September 2006, the FASB issued 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” (SFAS 157-1) which amends SFAS 157 to exclude SFAS 13 “Accounting for Leases” (SFAS 13) 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” (SFAS 157-2) 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 FSP was effective upon issuance. The adoption of this standard had no impact on the Registrant Subsidiaries’ financial statements.
The Registrant Subsidiaries partially adopted SFAS 157 effective January 1, 2008. The Registrant Subsidiaries will fully adopt SFAS 157 effective January 1, 2009 for items within the scope of FSP SFAS 157-2. Management expects that the adoption of FSP SFAS 157-2 will have an immaterial impact on the financial statements. 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, APCo, CSPCo and OPCo reduced beginning retained earnings by $440 thousand ($286 thousand, net of tax), $486 thousand ($316 thousand, net of tax) and $434 thousand ($282 thousand, net of tax), respectively, for the transition adjustment. SWEPCo’s transition adjustment was a favorable $16 thousand ($10 thousand, net of tax) adjustment to beginning retained earnings. The impact of considering AEP’s credit risk when measuring the fair value of liabilities, including derivatives, had an immaterial impact on fair value measurements upon adoption.
In accordance with SFAS 157, assets and liabilities are classified based on the inputs utilized in the fair value measurement. SFAS 157 provides definitions for two types of inputs: observable and unobservable. Observable inputs are valuation inputs that reflect the assumptions market participants would use in pricing the asset or liability developed based on market data obtained from sources independent of the reporting entity. Unobservable inputs are valuation inputs that reflect the reporting entity’s own assumptions about the assumptions market participants would use in pricing the asset or liability developed based on the best information in the circumstances.
As defined in SFAS 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement).
Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 1 inputs primarily consist of exchange traded contracts, listed equities and U.S. government treasury securities that exhibit sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 inputs are inputs other than quoted prices included within level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, exchange traded contracts where there was not sufficient market activity to warrant inclusion in level 1, OTC broker quotes that are corroborated by the same or similar transactions that have occurred in the market and certain non-exchange-traded debt securities.
Level 3 inputs are unobservable inputs for the asset or liability. Unobservable inputs shall be used to measure fair value to the extent that the observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Level 3 inputs primarily consist of unobservable market data or are valued based on models and/or assumptions.
Risk Management Contracts include exchange traded, OTC and bilaterally executed derivative contracts. Exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified within level 1. Other actively traded derivative fair values are verified using broker or dealer quotations, similar observable market transactions in either the listed or OTC markets, or valued using pricing models where significant valuation inputs are directly or indirectly observable in active markets. Derivative instruments, primarily swaps, forwards, and options that meet these characteristics are classified within level 2. Bilaterally executed agreements are derivative contracts entered into directly with third parties, and at times these instruments may be complex structured transactions that are tailored to meet the specific customer’s energy requirements. Structured transactions utilize pricing models that are widely accepted in the energy industry to measure fair value. Generally, management uses a consistent modeling approach to value similar instruments. Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data), and other observable inputs for the asset or liability. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in level 2. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. In addition, long-dated and illiquid complex or structured transactions can introduce the need for internally developed modeling inputs based upon extrapolations and assumptions of observable market data to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in level 3. In certain instances, the fair values of the transactions that use internally developed model inputs, classified as level 3 are offset partially or in full, by transactions included in level 2 where observable market data exists for the offsetting transaction.
The following table sets forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2008. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of September 30, 2008
APCo | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Risk Management Assets: | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 7,275 | | | $ | 553,289 | | | $ | 5,005 | | | $ | (447,811 | ) | | $ | 117,758 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 10,120 | | | | - | | | | (4,980 | ) | | | 5,140 | |
Dedesignated Risk Management Contracts (b) | | | - | | | | - | | | | - | | | | 14,259 | | | | 14,259 | |
Total Risk Management Assets | | $ | 7,275 | | | $ | 563,409 | | | $ | 5,005 | | | $ | (438,532 | ) | | $ | 137,157 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities: | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 10,589 | | | $ | 518,486 | | | $ | 9,646 | | | $ | (440,158 | ) | | $ | 98,563 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 7,976 | | | | - | | | | (4,980 | ) | | | 2,996 | |
DETM Assignment (c) | | | - | | | | - | | | | - | | | | 6,321 | | | | 6,321 | |
Total Risk Management Liabilities | | $ | 10,589 | | | $ | 526,462 | | | $ | 9,646 | | | $ | (438,817 | ) | | $ | 107,880 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of September 30, 2008
CSPCo | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Other Cash Deposits (e) | | $ | 31,002 | | | $ | - | | | $ | - | | | $ | 962 | | | $ | 31,964 | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets: | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 4,083 | | | $ | 286,118 | | | $ | 2,811 | | | $ | (232,301 | ) | | $ | 60,711 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 5,189 | | | | - | | | | (2,795 | ) | | | 2,394 | |
Dedesignated Risk Management Contracts (b) | | | - | | | | - | | | | - | | | | 8,005 | | | | 8,005 | |
Total Risk Management Assets | | $ | 4,083 | | | $ | 291,307 | | | $ | 2,811 | | | $ | (227,091 | ) | | $ | 71,110 | |
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 35,085 | | | $ | 291,307 | | | $ | 2,811 | | | $ | (226,129 | ) | | $ | 103,074 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities: | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 5,945 | | | $ | 266,791 | | | $ | 5,406 | | | $ | (227,981 | ) | | $ | 50,161 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 4,477 | | | | - | | | | (2,795 | ) | | | 1,682 | |
DETM Assignment (c) | | | - | | | | - | | | | - | | | | 3,549 | | | | 3,549 | |
Total Risk Management Liabilities | | $ | 5,945 | | | $ | 271,268 | | | $ | 5,406 | | | $ | (227,227 | ) | | $ | 55,392 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of September 30, 2008
I&M | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Risk Management Assets: | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 3,952 | | | $ | 283,053 | | | $ | 2,721 | | | $ | (230,057 | ) | | $ | 59,669 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 5,022 | | | | - | | | | (2,705 | ) | | | 2,317 | |
Dedesignated Risk Management Contracts (b) | | | - | | | | - | | | | - | | | | 7,747 | | | | 7,747 | |
Total Risk Management Assets | | $ | 3,952 | | | $ | 288,075 | | | $ | 2,721 | | | $ | (225,015 | ) | | $ | 69,733 | |
| | | | | | | | | | | | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts: | | | | | | | | | | | | | | | | | | | | |
Cash and Cash Equivalents (d) | | $ | - | | | $ | 3,523 | | | $ | - | | | $ | 6,328 | | | $ | 9,851 | |
Debt Securities (f) | | | - | | | | 837,141 | | | | - | | | | - | | | | 837,141 | |
Equity Securities (g) | | | 444,994 | | | | - | | | | - | | | | - | | | | 444,994 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | | $ | 444,994 | | | $ | 840,664 | | | $ | - | | | $ | 6,328 | | | $ | 1,291,986 | |
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 448,946 | | | $ | 1,128,739 | | | $ | 2,721 | | | $ | (218,687 | ) | | $ | 1,361,719 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities: | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 5,754 | | | $ | 264,220 | | | $ | 5,234 | | | $ | (225,884 | ) | | $ | 49,324 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 4,333 | | | | - | | | | (2,705 | ) | | | 1,628 | |
DETM Assignment (c) | | | - | | | | - | | | | - | | | | 3,435 | | | | 3,435 | |
Total Risk Management Liabilities | | $ | 5,754 | | | $ | 268,553 | | | $ | 5,234 | | | $ | (225,154 | ) | | $ | 54,387 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of September 30, 2008
OPCo | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Other Cash Deposits (e) | | $ | 3,116 | | | $ | - | | | $ | - | | | $ | 2,164 | | | $ | 5,280 | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets: | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 5,059 | | | $ | 582,635 | | | $ | 3,476 | | | $ | (481,108 | ) | | $ | 110,062 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 6,428 | | | | - | | | | (3,463 | ) | | | 2,965 | |
Dedesignated Risk Management Contracts (b) | | | - | | | | - | | | | - | | | | 9,917 | | | | 9,917 | |
Total Risk Management Assets | | $ | 5,059 | | | $ | 589,063 | | | $ | 3,476 | | | $ | (474,654 | ) | | $ | 122,944 | |
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 8,175 | | | $ | 589,063 | | | $ | 3,476 | | | $ | (472,490 | ) | | $ | 128,224 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities: | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 7,365 | | | $ | 552,724 | | | $ | 6,809 | | | $ | (476,017 | ) | | $ | 90,881 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 6,633 | | | | - | | | | (3,463 | ) | | | 3,170 | |
DETM Assignment (c) | | | - | | | | - | | | | - | | | | 4,396 | | | | 4,396 | |
Total Risk Management Liabilities | | $ | 7,365 | | | $ | 559,357 | | | $ | 6,809 | | | $ | (475,084 | ) | | $ | 98,447 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of September 30, 2008
PSO | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Risk Management Assets: | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 3,743 | | | $ | 141,674 | | | $ | 3,803 | | | $ | (121,851 | ) | | $ | 27,369 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | - | | | | - | | | | - | | | | - | |
Total Risk Management Assets | | $ | 3,743 | | | $ | 141,674 | | | $ | 3,803 | | | $ | (121,851 | ) | | $ | 27,369 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities: | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 3,677 | | | $ | 140,064 | | | $ | 5,010 | | | $ | (121,399 | ) | | $ | 27,352 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | - | | | | - | | | | - | | | | - | |
DETM Assignment (c) | | | - | | | | - | | | | - | | | | 222 | | | | 222 | |
Total Risk Management Liabilities | | $ | 3,677 | | | $ | 140,064 | | | $ | 5,010 | | | $ | (121,177 | ) | | $ | 27,574 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of September 30, 2008
SWEPCo | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Risk Management Assets: | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 4,412 | | | $ | 177,218 | | | $ | 4,481 | | | $ | (152,334 | ) | | $ | 33,777 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 44 | | | | - | | | | (44 | ) | | | - | |
Total Risk Management Assets | | $ | 4,412 | | | $ | 177,262 | | | $ | 4,481 | | | $ | (152,378 | ) | | $ | 33,777 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities: | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 4,334 | | | $ | 175,106 | | | $ | 5,909 | | | $ | (151,815 | ) | | $ | 33,534 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 227 | | | | - | | | | (44 | ) | | | 183 | |
DETM Assignment (c) | | | - | | | | - | | | | - | | | | 262 | | | | 262 | |
Total Risk Management Liabilities | | $ | 4,334 | | | $ | 175,333 | | | $ | 5,909 | | | $ | (151,597 | ) | | $ | 33,979 | |
(a) | Amounts in “Other” column primarily represent counterparty netting of risk management contracts and associated cash collateral under FSP FIN 39-1. |
(b) | “Dedesignated Risk Management Contracts” are contracts that were originally MTM but were subsequently elected as normal under SFAS 133. At the time of the normal election the MTM value was frozen and no longer fair valued. This will be amortized into Utility Operations Revenues over the remaining life of the contract. |
(c) | See “Natural Gas Contracts with DETM” section of Note 16 in the 2007 Annual Report. |
(d) | Amounts in “Other” column primarily represent accrued interest receivables to/from financial institutions. Level 2 amounts primarily represent investments in money market funds. |
(e) | Amounts in “Other” column primarily represent cash deposits with third parties. Level 1 amounts primarily represent investments in money market funds. |
(f) | Amounts represent corporate, municipal and treasury bonds. |
(g) | Amounts represent publicly traded equity securities. |
The following tables set forth a reconciliation of changes in the fair value of net trading derivatives and other investments classified as level 3 in the fair value hierarchy:
Three Months Ended September 30, 2008 | | APCo | | | CSPCo | | | I&M | | | OPCo | | | PSO | | | SWEPCo | |
| | (in thousands) | |
Balance as of July 1, 2008 | | $ | (18,560 | ) | | $ | (11,122 | ) | | $ | (10,675 | ) | | $ | (13,245 | ) | | $ | (23 | ) | | $ | (45 | ) |
Realized (Gain) Loss Included in Earnings (or Changes in Net Assets) (a) | | | 4,466 | | | | 2,670 | | | | 2,561 | | | | 3,287 | | | | 4 | | | | 13 | |
Unrealized Gain (Loss) Included in Earnings (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | | - | | | | (1,317 | ) | | | - | | | | (1,574 | ) | | | - | | | | 26 | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
Purchases, Issuances and Settlements | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
Transfers in and/or out of Level 3 (b) | | | 5,595 | | | | 3,360 | | | | 3,228 | | | | 3,914 | | | | (1,249 | ) | | | (1,471 | ) |
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | | | 3,858 | | | | 3,814 | | | | 2,373 | | | | 4,285 | | | | 61 | | | | 49 | |
Balance as of September 30, 2008 | | $ | (4,641 | ) | | $ | (2,595 | ) | | $ | (2,513 | ) | | $ | (3,333 | ) | | $ | (1,207 | ) | | $ | (1,428 | ) |
Nine Months Ended September 30, 2008 | | APCo | | | CSPCo | | | I&M | | | OPCo | | | PSO | | | SWEPCo | |
| | (in thousands) | |
Balance as of January 1, 2008 | | $ | (697 | ) | | $ | (263 | ) | | $ | (280 | ) | | $ | (1,607 | ) | | $ | (243 | ) | | $ | (408 | ) |
Realized (Gain) Loss Included in Earnings (or Changes in Net Assets) (a) | | | 332 | | | | 88 | | | | 105 | | | | 1,063 | | | | 170 | | | | 290 | |
Unrealized Gain (Loss) Included in Earnings (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | | - | | | | 190 | | | | - | | | | 126 | | | | - | | | | 56 | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
Purchases, Issuances and Settlements | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
Transfers in and/or out of Level 3 (b) | | | (731 | ) | | | (454 | ) | | | (430 | ) | | | (244 | ) | | | (1,249 | ) | | | (1,472 | ) |
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | | | (3,545 | ) | | | (2,156 | ) | | | (1,908 | ) | | | (2,671 | ) | | | 115 | | | | 106 | |
Balance as of September 30, 2008 | | $ | (4,641 | ) | | $ | (2,595 | ) | | $ | (2,513 | ) | | $ | (3,333 | ) | | $ | (1,207 | ) | | $ | (1,428 | ) |
(a) | Included in revenues on the Condensed Statements of Income. |
(b) | “Transfers in and/or out of Level 3” represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period. |
(c) | “Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected on the Condensed Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities. |
SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159)
In February 2007, the FASB issued 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.
The Registrant Subsidiaries adopted SFAS 159 effective January 1, 2008. At adoption, the Registrant Subsidiaries did not elect the fair value option for any assets or liabilities.
SFAS 160 “Noncontrolling Interest in Consolidated Financial Statements” (SFAS 160)
In December 2007, the FASB issued SFAS 160, modifying reporting for noncontrolling interest (minority interest) in consolidated financial statements. ItThe statement requires noncontrolling interest be reported in equity and establishes a new framework for recognizing net income or loss and comprehensive income by the controlling interest. Upon deconsolidation due to loss of control over a subsidiary, the standard requires a fair value remeasurement of any remaining noncontrolling equity investment to be used to properly recognize the gain or loss. SFAS 160 requires specific disclosures regarding changes in equity interest of both the controlling and noncontrolling parties and presentation of the noncontrolling equity balance and income or loss for all periods presented.
SFAS 160 is effective for interim and annual periods in fiscal years beginning after December 15, 2008. The statement is applied prospectively upon adoption. Early adoption is prohibited. Upon adoption, prior period financial statements will be restated for the presentation of the noncontrolling interest for comparability. Management expects that the adoption of this standard will have an immaterial impact on the financial statements. The Registrant Subsidiaries will adoptadopted SFAS 160 effective January 1, 2009.2009 and retrospectively applied the standard to prior periods. The adoption of SFAS 160 had no impact on APCo, CSPCo, I&M and PSO. The retrospective application of this standard impacted OPCo and SWEPCo as follows:
OPCo:
· | Reclassifies Interest Expense of $463 thousand for the three months ended March 31, 2008 as Net Income Attributable to Noncontrolling Interest below Net Income in the presentation of Earnings Attributable to OPCo Common Shareholder in its Condensed Consolidated Statements of Income. |
· | Reclassifies minority interest of $16.8 million as of December 31, 2008 previously included in Deferred Credits and Other and Total Liabilities as Noncontrolling Interest in Total Equity on its Condensed Consolidated Balance Sheets. |
· | Separately reflects changes in Noncontrolling Interest in its Statements of Changes in Equity and Comprehensive Income (Loss). |
· | Reclassifies dividends paid to noncontrolling interests of $463 thousand for the three months ended March 31, 2008 from Operating Activities to Financing Activities in the Condensed Consolidated Statements of Cash Flows. |
SWEPCo:
· | Reclassifies Minority Interest Expense of $995 thousand for the three months ended March 31, 2008 as Net Income Attributable to Noncontrolling Interest below Net Income in the presentation of Earnings Attributable to SWEPCo Common Shareholder in its Condensed Consolidated Statements of Income. |
· | Reclassifies minority interest of $276 thousand as of December 31, 2008 previously included in Deferred Credits and Other and Total Liabilities as Noncontrolling Interest in Total Equity on its Condensed Consolidated Balance Sheets. |
· | Separately reflects changes in Noncontrolling Interest in the Statements of Changes in Equity and Comprehensive Income (Loss). |
· | Reclassifies dividends paid to noncontrolling interests of $949 thousand for the three months ended March 31, 2008 from Operating Activities to Financing Activities in the Condensed Consolidated Statements of Cash Flows. |
SFAS 161 “Disclosures about Derivative Instruments and Hedging Activities” (SFAS 161)
In March 2008, the FASB issued SFAS 161, enhancing disclosure requirements for derivative instruments and hedging activities. Affected entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how an entity accounts for derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS 161The standard requires that objectives for using derivative instruments be disclosed in terms of the primary underlying risk and accounting designation.
The Registrant Subsidiaries adopted SFAS 161 effective January 1, 2009. This standard is intended to improve uponincreased the existing disclosure framework in SFAS 133.
SFAS 161 is effective for fiscal years and interim periods beginning after November 15, 2008. Management expects this standard to increase the disclosure requirementsdisclosures related to derivative instruments and hedging activities. It encourages retrospective application to comparative disclosureSee “Derivatives and Hedging” section of Note 7 for earlier periods presented. The Registrant Subsidiaries will adopt SFAS 161 effective January 1, 2009.further information.
SFAS 162 “The Hierarchy of Generally Accepted Accounting Principles” (SFAS 162)
In May 2008, the FASB issued SFAS 162, clarifying the sources of generally accepted accounting principles in descending order of authority. The statement specifies that the reporting entity, not its auditors, is responsible for its compliance with GAAP.
SFAS 162 is effective 60 days after the SEC approves the Public Company Accounting Oversight Board’s amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” Management expects the adoption of this standard will have no impact on the Registrant Subsidiaries’ financial statements. The Registrant Subsidiaries will adopt SFAS 162 when it becomes effective.
EITF Issue No. 06-10 “Accounting for Collateral Assignment Split-Dollar Life Insurance Arrangements”
(EITF 06-10)
In March 2007, the FASB ratified 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'08-5 “Issuer’s 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 employeeLiabilities Measured at Fair Value 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. The Registrant Subsidiaries adopted EITF 06-10 effective January 1, 2008. The impact of this standard was an unfavorable cumulative effect adjustment, net of tax, to beginning retained earnings as follows:Third-Party Credit
| | Retained | | | |
| | Earnings | | Tax | |
Company | | Reduction | | Amount | |
| | (in thousands) | |
APCo | | | $ | 2,181 | | | $ | 1,175 | |
CSPCo | | | | 1,095 | | | | 589 | |
I&M | | | | 1,398 | | | | 753 | |
OPCo | | | | 1,864 | | | | 1,004 | |
PSO | | | | 1,107 | | | | 596 | |
SWEPCo | | | | 1,156 | | | | 622 | |
Enhancement” (EITF 08-5)
EITF Issue No. 06-11 “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards”
(EITF 06-11)
In June 2007, the FASB ratified the EITF 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. 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 Registrant Subsidiaries adopted EITF 06-11 effective January 1, 2008. The adoption of this standard had an immaterial impact on the financial statements.
EITF Issue No. 08-5 “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement” (EITF 08-5) |
In September 2008, the FASB ratified the EITF consensus on liabilities with third-party credit enhancements when the liability is measured and disclosed at fair value. The consensus treats the liability and the credit enhancement as two units of accounting. Under the consensus, the fair value measurement of the liability does not include the effect of the third-party credit enhancement. Consequently, changes in the issuer’s credit standing without the support of the credit enhancement affect the fair value measurement of the issuer’s liability. Entities will need to provide disclosures about the existence of any third-party credit enhancements related to their liabilities.
EITF 08-5 is effective for the first reporting period beginning after December 15, 2008. It will be applied prospectively upon adoption with the effect of initial application included as a change in fair value of the liability in the period of adoption. In the period of adoption, entities must disclose the valuation method(s) used to measure the fair value of liabilities within its scope and any change in the fair value measurement method that occurs as a result of its initial application. Early adoption is permitted. Although management has not completed
The Registrant Subsidiaries adopted EITF 08-5 effective January 1, 2009. It will be applied prospectively with the effect of initial application included as a change in fair value of the liability.
EITF Issue No. 08-6 “Equity Method Investment Accounting Considerations” (EITF 08-6)
In November 2008, the FASB ratified the consensus on equity method investment accounting including initial and allocated carrying values and subsequent measurements. It requires initial carrying value be determined using the SFAS 141R cost allocation method. When an analysis, management expects thatinvestee issues shares, the adoptionequity method investor should treat the transaction as if the investor sold part of this standard will have an immaterialits interest.
The Registrant Subsidiaries adopted EITF 08-6 effective January 1, 2009 with no impact on the financial statements. The Registrant Subsidiaries will adopt this standard effective January 1, 2009.
FSP SFAS 133-1 and FIN 45-4 “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No.133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161” (SFAS 133-1 and FIN 45-4)
In September 2008, the FASB issued SFAS 133-1 and FIN 45-4 as amendments to original statements SFAS 133 and FIN 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” Under the SFAS 133 requirements, the seller of a credit derivative shall disclose the following information for each derivative, including credit derivatives embedded in a hybrid instrument, even if the likelihood of payment is remote:
(a) | The nature of the credit derivative. |
(b) | The maximum potential amount of future payments. |
(c) | The fair value of the credit derivative. |
(d) | The nature of any recourse provisions and any assets held as collateral or by third parties. |
Further, the standard requires the disclosure of current payment status/performance risk of all FIN 45 guarantees. In the event an entity uses internal groupings, the entity shall disclose how those groupings are determined and used for managing risk.
The standard is effective for interim and annual reporting periods ending after November 15, 2008. Upon adoption, the guidance will be prospectively applied. Management expects that the adoption of this standard will have an immaterial impact on the financial statements but increase the FIN 45 guarantees disclosure requirements. The Registrant Subsidiaries will adopt the standard effective December 31, 2008.It was applied prospectively.
FSP SFAS 142-3 “Determination of the Useful Life of Intangible Assets” (SFAS 142-3)
In April 2008, the FASB issued SFAS 142-3 amending factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS 142, “Goodwill and Other Intangible Assets.”asset. The standard is expected to improve consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure its fair value.
The Registrant Subsidiaries adopted SFAS 142-3 is effective for interim and annual periods in fiscal years beginning after December 15, 2008. Early adoptionJanuary 1, 2009. The guidance is prohibited. Upon adoption, the guidance within SFAS 142-3 will be prospectively applied to intangible assets acquired after the effective date. Management expects that theThe standard’s disclosure requirements are applied prospectively to all intangible assets as of January 1, 2009. The adoption of this standard will have an immaterialhad no impact on the Registrant Subsidiaries’ financial statements. The Registrant Subsidiaries will adopt SFAS 142-3 effective January 1, 2009.
FSP FIN 39-1 “AmendmentSFAS 157-2 “Effective Date of FASB InterpretationStatement No. 39” (FIN 39-1)157” (SFAS 157-2)
In April 2007,February 2008, the FASB issued FIN 39-1. It amends FASB Interpretation No. 39 “OffsettingSFAS 157-2 which delays the effective date of Amounts RelatedSFAS 157 to Certain Contracts” by replacingfiscal 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 interpretation’s definition of contracts withfinancial statements on a recurring basis (at least annually). As defined in SFAS 157, fair value is the definition of derivative instruments per SFAS 133. It also requires entitiesprice that offset fair values of derivatives with the same party underwould be received to sell an asset or paid to transfer a netting agreement to also 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 receivablesliability in an orderly transaction between market participants at the endmeasurement date. The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs. In the absence of each reporting period.quoted prices for identical or similar assets or investments in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.
The Registrant Subsidiaries adopted FIN 39-1SFAS 157-2 effective January 1, 2008. This standard changed the method of netting certain balance sheet amounts2009. The Registrant Subsidiaries will apply these requirements to applicable fair value measurements which include new asset retirement obligations and reducedimpairment analysis related to long-lived assets, equity investments, goodwill and intangibles. The Registrant Subsidiaries did not record any fair value measurements for nonrecurring nonfinancial assets and liabilities. It requires retrospective application as a changeliabilities in accounting principle. Consequently, the Registrant Subsidiaries reclassified the following amounts on their December 31, 2007 balance sheets as shown:first quarter of 2009.
APCo | | | | | | |
| | As Reported for | | | | As Reported for |
Balance Sheet | | the December 2007 | | FIN 39-1 | | the September 2008 |
Line Description | | 10-K | | Reclassification | | 10-Q |
Current Assets: | | (in thousands) |
Risk Management Assets | | $ | 64,707 | | $ | (1,752) | | $ | 62,955 |
Prepayments and Other | | | 19,675 | | | (3,306) | | | 16,369 |
Long-term Risk Management Assets | | | 74,954 | | | (2,588) | | | 72,366 |
| | | | | | | | | |
Current Liabilities: | | | | | | | | | |
Risk Management Liabilities | | | 54,955 | | | (3,247) | | | 51,708 |
Customer Deposits | | | 50,260 | | | (4,340) | | | 45,920 |
Long-term Risk Management Liabilities | | | 47,416 | | | (59) | | | 47,357 |
Pronouncements Effective in the Future
CSPCo | | | | | | |
| | As Reported for | | | | As Reported for |
Balance Sheet | | the December 2007 | | FIN 39-1 | | the September 2008 |
Line Description | | 10-K | | Reclassification | | 10-Q |
Current Assets: | | (in thousands) |
Risk Management Assets | | $ | 34,564 | | $ | (1,006) | | $ | 33,558 |
Prepayments and Other | | | 11,877 | | | (1,917) | | | 9,960 |
Long-term Risk Management Assets | | | 43,352 | | | (1,500) | | | 41,852 |
| | | | | | | | | |
Current Liabilities: | | | | | | | | | |
Risk Management Liabilities | | | 30,118 | | | (1,881) | | | 28,237 |
Customer Deposits | | | 45,602 | | | (2,507) | | | 43,095 |
Long-term Risk Management Liabilities | | | 27,454 | | | (35) | | | 27,419 |
The following standards will be effective in the future and their impacts disclosed at that time.
I&M | | | | | | |
| | As Reported for | | | | As Reported for |
Balance Sheet | | the December 2007 | | FIN 39-1 | | the September 2008 |
Line Description | | 10-K | | Reclassification | | 10-Q |
Current Assets: | | (in thousands) |
Risk Management Assets | | $ | 33,334 | | $ | (969) | | $ | 32,365 |
Prepayments and Other | | | 12,932 | | | (1,841) | | | 11,091 |
Long-term Risk Management Assets | | | 41,668 | | | (1,441) | | | 40,227 |
| | | | | | | | | |
Current Liabilities: | | | | | | | | | |
Risk Management Liabilities | | | 29,078 | | | (1,807) | | | 27,271 |
Customer Deposits | | | 28,855 | | | (2,410) | | | 26,445 |
Long-term Risk Management Liabilities | | | 26,382 | | | (34) | | | 26,348 |
OPCo | | | | | | |
| | As Reported for | | | | As Reported for |
Balance Sheet | | the December 2007 | | FIN 39-1 | | the September 2008 |
Line Description | | 10-K | | Reclassification | | 10-Q |
Current Assets: | | (in thousands) |
Risk Management Assets | | $ | 45,490 | | $ | (1,254) | | $ | 44,236 |
Prepayments and Other | | | 20,532 | | | (2,232) | | | 18,300 |
Long-term Risk Management Assets | | | 51,334 | | | (1,748) | | | 49,586 |
| | | | | | | | | |
Current Liabilities: | | | | | | | | | |
Risk Management Liabilities | | | 42,740 | | | (2,192) | | | 40,548 |
Customer Deposits | | | 33,615 | | | (3,002) | | | 30,613 |
Long-term Risk Management Liabilities | | | 32,234 | | | (40) | | | 32,194 |
FSP SFAS 107-1 and APB 28-1 “Interim Disclosures about Fair Value of Financial Instruments” (FSP SFAS 107-1 and APB 28-1) |
PSO | | | | | | |
| | As Reported for | | | | As Reported for |
Balance Sheet | | the December 2007 | | FIN 39-1 | | the September 2008 |
Line Description | | 10-K | | Reclassification | | 10-Q |
Current Assets: | | (in thousands) |
Risk Management Assets | | $ | 33,338 | | $ | (30) | | $ | 33,308 |
Margin Deposits | | | 9,119 | | | (139) | | | 8,980 |
Long-term Risk Management Assets | | | 3,376 | | | (18) | | | 3,358 |
| | | | | | | | | |
Current Liabilities: | | | | | | | | | |
Risk Management Liabilities | | | 27,151 | | | (33) | | | 27,118 |
Customer Deposits | | | 41,525 | | | (48) | | | 41,477 |
Long-term Risk Management Liabilities | | | 2,914 | | | (106) | | | 2,808 |
In April 2009, the FASB issued FSP SFAS 107-1 and APB 28-1 requiring disclosure about the fair value of financial instruments in all interim reporting periods. The standard requires disclosure of the method and significant assumptions used to determine the fair value of financial instruments.
SWEPCo | | | | | | |
| | As Reported for | | | | As Reported for |
Balance Sheet | | the December 2007 | | FIN 39-1 | | the September 2008 |
Line Description | | 10-K | | Reclassification | | 10-Q |
Current Assets: | | (in thousands) |
Risk Management Assets | | $ | 39,893 | | $ | (43) | | $ | 39,850 |
Margin Deposits | | | 10,814 | | | (164) | | | 10,650 |
Long-term Risk Management Assets | | | 4,095 | | | (22) | | | 4,073 |
| | | | | | | | | |
Current Liabilities: | | | | | | | | | |
Risk Management Liabilities | | | 32,668 | | | (39) | | | 32,629 |
Customer Deposits | | | 37,537 | | | (64) | | | 37,473 |
Long-term Risk Management Liabilities | | | 3,460 | | | (126) | | | 3,334 |
This standard is effective for interim periods ending after June 15, 2009. Management expects this standard to increase the disclosure requirements related to financial instruments. The Registrant Subsidiaries will adopt the standard effective second quarter of 2009.
FSP SFAS 115-2 and SFAS 124-2 “Recognition and Presentation of Other-Than-Temporary Impairments” (FSP SFAS 115-2 and SFAS 124-2) |
In April 2009, the FASB issued FSP SFAS 115-2 and SFAS 124-2 amending the other-than-temporary impairment (OTTI) recognition and measurement guidance for debt securities. For certainboth debt and equity securities, the standard requires disclosure for each interim reporting period of information by security class similar to previous annual disclosure requirements.
This standard is effective for interim periods ending after June 15, 2009. Management does not expect a material impact as a result of the new OTTI evaluation method for debt securities, but expects this standard to increase the disclosure requirements related to financial instruments. The Registrant Subsidiaries will adopt the standard effective second quarter of 2009.
FSP SFAS 132R-1 “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP SFAS 132R-1)
In December 2008, the FASB issued FSP SFAS 132R-1 providing additional disclosure guidance for pension and OPEB plan assets. The rule requires disclosure of investment policy including target allocations by investment class, investment goals, risk management contracts,policies and permitted or prohibited investments. It specifies a minimum of investment classes by further dividing equity and debt securities by issuer grouping. The standard adds disclosure requirements including hierarchical classes for fair value and concentration of risk.
This standard is effective for fiscal years ending after December 15, 2009. Management expects this standard to increase the disclosure requirements related to AEP’s benefit plans. The Registrant Subsidiaries are required to postwill adopt the standard effective for the 2009 Annual Report.
FSP SFAS 157-4 “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (FSP SFAS 157-4) |
In April 2009, the FASB issued FSP SFAS 157-4 providing additional guidance on estimating fair value when the volume and level of activity for an asset or receive cash collateralliability has significantly decreased, including guidance on identifying circumstances indicating when a transaction is not orderly. Fair value measurements shall be based on third party contractual agreementsthe price that would be received to sell an asset or paid to transfer a liability in an orderly (not a distressed sale or forced liquidation) transaction between market participants at the measurement date under current market conditions. The standard also requires disclosures of the inputs and risk profiles. Forvaluation techniques used to measure fair value and a discussion of changes in valuation techniques and related inputs, if any, for both interim and annual periods.
This standard is effective for interim and annual periods ending after June 15, 2009. Management expects this standard to have no impact on the September 30, 2008 balance sheets, thefinancial statement but will increase disclosure requirements. The Registrant Subsidiaries netted collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows:
| September 30, 2008 | |
| Cash Collateral | | Cash Collateral | |
| Received | | Paid | |
| Netted Against | | Netted Against | |
| Risk Management | | Risk Management | |
| Assets | | Liabilities | |
| (in thousands) | |
APCo | | $ | 8,250 | | | $ | 597 | |
CSPCo | | | 4,631 | | | | 311 | |
I&M | | | 4,482 | | | | 309 | |
OPCo | | | 5,747 | | | | 656 | |
PSO | | | 499 | | | | 47 | |
SWEPCo | | | 588 | | | | 69 | |
will adopt the standard effective second quarter of 2009.
Future Accounting Changes
The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued by FASB, management cannot determine the impact on the reporting of the Registrant Subsidiaries’ operations and financial position that may result from any such future changes. The FASB is currently working on several projects including revenue recognition, contingencies, liabilities and equity, emission allowances, leases, insurance, hedge accounting, consolidation policy,discontinued operations, trading inventory and related tax impacts. Management also expects to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP. The ultimate pronouncements resulting from these and future projects could have an impact on future net income and financial position.
EXTRAORDINARY ITEM
APCo recorded an extraordinary loss of $118 million ($79 million, net of tax) during the second quarter of 2007 for the establishment of regulatory assets and liabilities related to the Virginia generation operations. In 2000, APCo discontinued SFAS 71 regulatory accounting for the Virginia jurisdiction due to the passage of legislation for customer choice and deregulation. In April 2007, Virginia passed legislation to establish electric regulation again.
The Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 20072008 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 20082009 and updates the 20072008 Annual Report.
Ohio Rate Matters
Ohio Electric Security Plan Filings – Affecting CSPCo and OPCo
In AprilJuly 2008, as required by the 2008 amendments to 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. A MRO, from the date of its commencement, could transitionlegislation, CSPCo and OPCo to full market rates no sooner than six years and no later than ten years after the PUCO approves a MRO. The PUCO has the authority to approve or modify each utilities’ ESP request. The PUCO is required to approve an ESP if, in the aggregate, the ESP is more favorable to ratepayers than a 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 thefiled ESPs CSPCo and OPCo filed with the PUCO to establish rates for 2009 through 2011.standard service offer rates. CSPCo and OPCo did not file an optional MRO. CSPCoMarket Rate Offer (MRO). CSPCo’s and OPCo eachOPCo’s ESP filings requested an annual rate increase for 2009 through 2011 that would not exceed approximately 15% per year. A significant portion of the requested ESP increases resultsresulted from the implementation of a fuel cost recovery mechanism (which excludes off-system sales)adjustment clause (FAC) 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 inallowances and most other variable production costs. FAC costs were proposed to be phased into customer bills related to the fuel-purchased power cost recovery mechanism would be phased-in over the three yearthree-year period from 2009 through 2011. If the ESP is approved2011 with unrecovered FAC costs to be recorded as filed, effectivea FAC phase-in regulatory asset. The phase-in regulatory asset deferral along with January 2009 billings, CSPCo and OPCo will defer any fuela deferred weighted average cost under-recoveries and relatedof capital carrying costs for future recovery. The under-recoveries and related carrying costs that exist at the end of 2011 willcost was proposed to 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,March 2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s ESPs. The ESPs will be in effect through 2011. The ESP order authorized increases to revenues during the ESP period and capped the overall revenue increases through a findingphase-in of the FAC. The ordered increases for CSPCo are 7% in 2009, 6% in 2010 and order tentatively adopting rules governing MRO6% in 2011 and ESP applications.for OPCo are 8% in 2009, 7% in 2010 and 8% in 2011. After final PUCO review and approval of conforming rate schedules, CSPCo and OPCo filed their ESP applications based on proposed rulesimplemented rates for the April 2009 billing cycle. CSPCo and requested waiversOPCo will collect the 2009 annualized revenue increase over the remainder of 2009.
The order provides a FAC for portionsthe three-year period of the proposed rules.ESP. The PUCO deniedFAC increase will be phased in to meet the waiver requests in September 2008ordered annual caps described above. The FAC increase before phase-in will be subject to quarterly true-ups to actual recoverable FAC costs and orderedto annual accounting audits and prudency reviews. The order allows CSPCo and OPCo to submit information consistent withdefer unrecovered FAC costs resulting from the tentative rules. In October 2008,annual caps/phase-in plan and to accrue carrying charges on such deferrals at CSPCo’s and OPCo’s weighted average cost of capital. The deferred FAC balance at the end of the ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018. As of March 31, 2009, the FAC deferral balances were $17 million and $66 million for CSPCo and OPCo, submitted additional information relatedrespectively, including carrying charges. The PUCO rejected a proposal by several intervenors to proforma financial statements and information concerning CSPCo and OPCo’s fuel procurement process. In October 2008, CSPCo and OPCo filed an applicationoffset the FAC costs with a credit 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.
2008 Generation Rider and Transmission Rider Rate Settlement – Affecting CSPCo and OPCo
On January 30, 2008, the PUCO approved a settlement agreement, among CSPCo, OPCo and other parties, under the additional average 4% generation rate increase and transmission cost recovery rider (TCRR) provisions of the RSP. The increase was to recover additional governmentally-mandated costs including incremental environmental costs. Under the settlement, the PUCO also approved recovery through the TCRR of increased PJM costs associated with transmission line losses of $39 million each for CSPCo and OPCo.off-system sales margins. As a result, CSPCo and OPCo established regulatory assets duringwill retain the first quarterbenefit of 2008their share of $12 millionthe AEP System’s off-system sales. In addition, the ESP order provided for both the FAC deferral credits and $14 million, respectively, relatedthe off-system sales margins to be excluded from the future recovery of increased PJM billings previously expensed from June 2007 to December 2007 for transmission line losses. The PUCO also approved a credit applied to the TCRR of $10 million for OPCo and $8 million for CSPCo for a reduction in PJM net congestion costs. To the extent that collectionsmethodology for the TCRR recoveries are under/over actual netSignificantly Excessive Earnings Test (SEET). The SEET is discussed below.
Additionally, the order addressed several other items, including:
· | The approval of new distribution riders, subject to true-up for recovery of costs for enhanced vegetation management programs, for CSPCo and OPCo and the proposed gridSMART advanced metering initial program roll out in a portion of CSPCo’s service territory. The PUCO proposed that CSPCo mitigate the costs of gridSMART by seeking matching funds under the American Recovery and Reinvestment Act of 2009. As a result, a rider was established to recover 50% or $32 million of the projected $64 million revenue requirement related to gridSMART costs. The PUCO denied the other distribution system reliability programs proposed by CSPCo and OPCo as part of their ESP filings. The PUCO decided that those requests should be examined in the context of a complete distribution base rate case. The order did not require CSPCo and/or OPCo to file a distribution base rate case. |
· | The approval of CSPCo’s and OPCo’s request to recover the incremental carrying costs related to environmental investments made from 2001 through 2008 that are not reflected in existing rates. Future recovery during the ESP period of incremental carrying charges on environmental expenditures incurred beginning in 2009 may be requested in annual filings. |
· | The approval of a $97 million and $55 million increase in CSPCo’s and OPCo’s Provider of Last Resort charges, respectively, to compensate for the risk of customers changing electric suppliers during the ESP period. |
· | The requirement that CSPCo’s and OPCo’s shareholders fund a combined minimum of $15 million in costs over the ESP period for low-income, at-risk customer programs. This funding obligation was recognized as a liability and an unfavorable adjustment to Other Operation and Maintenance expense for the three-month period ending March 31, 2009. |
· | The deferral of CSPCo’s and OPCo’s request to recover certain existing regulatory assets, including customer choice implementation and line extension carrying costs as part of the ESPs. The PUCO decided it would be more appropriate to consider this request in the context of CSPCo’s and OPCo’s next distribution base rate case. These regulatory assets, which were approved by prior PUCO orders, total $58 million for CSPCo and $40 million for OPCo as of March 31, 2009. In addition, CSPCo and OPCo would recover and recognize as income, when collected, $35 million and $26 million, respectively, of related unrecorded equity carrying costs incurred through March 2009. |
Finally, consistent with its decisions on ESP orders of other companies, the PUCO ordered its staff to convene a workshop to determine the methodology for the SEET that will be applicable to all electric utilities in Ohio. The SEET requires the PUCO to determine, following the end of each year of the ESP, if any rate adjustments included in the ESP resulted in excessive earnings as measured by whether the earned return on common equity of CSPCo and OPCo will deferis significantly in excess of the difference as a regulatory asset or regulatory liabilityreturn on common equity that was earned during the same period by publicly traded companies, including utilities, that have comparable business and adjust future customer billingsfinancial risk. If the rate adjustments, in the aggregate, result in significantly excessive earnings in comparison, the PUCO must require that the amount of the excess be returned to reflect actual costs, including carrying costscustomers. The PUCO’s decision on the deferral. UnderSEET review of CSPCo’s and OPCo’s 2009 earnings is not expected to be finalized until the termssecond or third quarter of the settlement, although the increased PJM costs associated with transmission line losses will be recovered through the TCRR, these recoveries will still be applied to reduce the annual average 4% generation rate increase limitation. In addition, the PUCO approved recoveries through generation rates of environmental costs and related carrying costs of $29 million for CSPCo and $5 million for OPCo. These RSP rate adjustments were implemented in February 2008.2010.
Also, in February 2008, Ormet, a major industrial customer,In March 2009, intervenors filed a motion to intervenestay a portion of the ESP rates or alternately make that portion subject to refund because the intervenors believed that the ordered ESP rates for 2009 were retroactive and an application fortherefore unlawful. In March 2009, the PUCO approved CSPCo’s and OPCo’s tariffs effective with the April 2009 billing cycle and rejected the intervenors’ motion. The PUCO also clarified that the reference in its earlier order to the January 1, 2009 date related to the term of the ESP, not to the effective date of tariffs and clarified the tariffs were not retroactive. In March 2009, CSPCo and OPCo implemented the new ESP tariffs effective with the start of the April 2009 billing cycle. In April 2009, CSPCo and OPCo filed a motion requesting rehearing of several issues. In April 2009, several intervenors filed motions requesting rehearing of issues underlying the PUCO’s January 2008 RSP order claiming the settlement inappropriately shifted $4 million in cost recovery to Ormet. In March 2008,authorized rate increases and one intervenor filed a motion requesting the PUCO granted Ormet’s motion to intervene. Ormet’s rehearing applicationdirect CSPCo and OPCo to cease collecting rates under the order. Certain intervenors also was grantedfiled a complaint for writ of prohibition with the purposeOhio Supreme Court to halt any further collection from customers of providingwhat the PUCO with additional time to consider the issues raised by Ormet. Upon PUCO approval of an unrelated amendment to the Ormet contract, Ormet withdrew its rehearing application in August 2008.intervenors claim is unlawful retroactive rate increases.
Management will evaluate whether it will withdraw the ESP applications after a final order, thereby terminating the ESP proceedings. If CSPCo and/or OPCo withdraw the ESP applications, CSPCo and/or OPCo may file an MRO or another ESP as permitted by the law. The revenues collected and recorded in 2009 under this PUCO order are subject to possible refund through the SEET process. Management is unable, due to the decision of the PUCO to defer guidance on the SEET methodology to a future generic SEET proceeding, to estimate the amount, if any, of a possible refund that could result from the SEET process in 2010.
Ohio IGCC Plant – Affecting CSPCo and OPCo
In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs related to building and operating a 629 MW IGCC power plant using clean-coal technology. The application proposed three phases of cost recovery associated with the IGCC plant: Phase 1, recovery of $24 million in pre-construction costs; Phase 2, concurrent recovery of construction-financing costs; and Phase 3, recovery or refund in distribution rates of any difference between the generation rates which may be a market-based standard service offer price for generation and the expected higher cost of operating and maintaining the plant, including a return on and return of the projected cost to construct the plant.
In June 2006, the PUCO issued an order approving a tariff to allow CSPCo and OPCo to recover Phase 1 pre-construction costs over a period of no more than twelve months effective July 1, 2006. During that period, CSPCo and OPCo each collected $12 million in pre-construction costs and incurred $11 million in pre-construction costs. As a result, CSPCo and OPCo each established a net regulatory liability of approximately $1 million.
The order also provided that if CSPCo and OPCo have not commenced a continuous course of construction of the proposed IGCC plant within five years of the June 2006 PUCO order, all Phase 1pre-construction cost recoveries associated with items that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest. The PUCO deferred ruling on cost recovery for Phases 2 and 3 pending further hearings.
In August 2006, intervenors filed four separate appeals of the PUCO’s order in the IGCC proceeding. In March 2008, the Ohio Supreme Court issued its opinion affirming in part, and reversing in part the PUCO’s order and remanded the matter back to the PUCO. The Ohio Supreme Court held that while there could be an opportunity under existing law to recover a portion of the IGCC costs in distribution rates, traditional rate making procedures would apply to the recoverable portion. The Ohio Supreme Court did not address the matter of refunding the Phase 1 cost recovery and declined to create an exception to its precedent of denying claims for refund of past recoveries from approved orders of the PUCO. In September 2008, the Ohio Consumers’ Counsel filed a motion with the PUCO requesting all Phase 1pre-construction costs be refunded to Ohio ratepayers with interest because the Ohio Supreme Court invalidated the underlying foundation for the Phase 1 recovery.interest. In October 2008, CSPCo and OPCo filed a motion with the PUCO that argued the Ohio Consumers’ Counsel’s motion was without legal merit and contrary to past precedent.
In January 2009, a PUCO Attorney Examiner issued an order that CSPCo and OPCo file a detailed statement outlining the status of the construction of the IGCC plant, including whether CSPCo and OPCo are engaged in a continuous course of construction on the IGCC plant. In February 2009, CSPCo and OPCo filed a statement that CSPCo and OPCo have not commenced construction of the IGCC plant and believe there exist real statutory barriers to the construction of any new base load generation in Ohio, including IGCC plants. The statement also indicated that while construction on the IGCC plant might not begin by June 2011, changes in circumstances could result in the commencement of construction on a continuous course by that time.
Management continues to pursue the ultimate construction of the IGCC plant. However, CSPCo and OPCo will not start construction of the IGCC plant until sufficient assurance of regulatory cost recovery exists. If CSPCo and OPCo were required to refund the $24 million collected 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.
As Management cannot predict the outcome of December 31, 2007, the cost ofrecovery litigation concerning the plant was estimated at $2.7 billion. The estimated cost of the plant has continued to increase significantly. Management continues to pursue the ultimate construction of the IGCC plant. CSPCo and OPCo will not start construction of theOhio IGCC plant until sufficient assurance of regulatory cost recovery exists.or what, if any effect, the litigation will have on future net income and cash flows.
Ormet – Affecting CSPCo and OPCo
EffectiveIn December 2008, CSPCo, OPCo and Ormet, a large aluminum company with a load of 520 MW, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet. The arrangement would be effective January 1, 2007, CSPCo2009 and remain in effect and expire upon the effective date of CSPCo’s and OPCo’s new ESP rates and the effective date of a new arrangement between Ormet and CSPCo/OPCo began to serve Ormet, a major industrial customer with a 520 MW load, in accordance with a settlement agreementas approved by the PUCO. The settlement agreement allows forUnder the recoveryinterim arrangement, Ormet would pay the then-current applicable generation tariff rates and riders. CSPCo and OPCo sought to defer as a regulatory asset beginning in 2007 and 2008 of2009 the difference between the $43 per MWH Ormet pays for power and a PUCO-approved market price, if higher. The PUCO approved a $47.69 per MWH market price for 2007 and the difference was recovered through the amortization of a $57 million ($15 million for CSPCo and $42 million for OPCo) excess deferred tax regulatory liability resulting from an Ohio franchise tax phase-out recorded in 2005.
CSPCo and OPCo each amortized $8 million of this regulatory liability to income for the nine months ended September 30, 2008 based on the previously approved 2007 price of $47.69 per MWH. In December 2007, CSPCo and OPCo submitted for approval a market price of $53.03 per MWH for 2008. The PUCO has not yet approvedand the 2008 market price. If the PUCO approves a market price for 2008 below $47.69, it could have an adverse effect on future net incomeapplicable generation tariff rates and cash flows. A price above $47.69 should result in a favorable effect. Ifriders. CSPCo and OPCo serveproposed to recover the deferral through the fuel adjustment clause mechanism they proposed in the ESP proceeding. In January 2009, the PUCO approved the application as an interim arrangement. In February 2009, an intervenor filed an application for rehearing of the PUCO’s interim arrangement approval. In March 2009, the PUCO granted that application for further consideration of the matters specified in the rehearing application.
In February 2009, as amended in April 2009, Ormet filed an application with the PUCO for approval of a proposed Ormet power contract for 2009 through 2018. Ormet proposed to pay varying amounts based on certain conditions, including the price of aluminum and the level of production. The difference between the amounts paid by Ormet and the otherwise applicable PUCO ESP tariff rate would be either collected from or refunded to CSPCo’s and OPCo’s retail customers.
In March 2009, the PUCO issued an order in the ESP filings which included approval of a FAC for the ESP period. The approval of an ESP FAC, together with the January 2009 PUCO approval of the Ormet load after 2008 without any special provisions, they could experience incremental costsinterim arrangement, provided the basis to acquire additional capacity to meet their reserve requirements and/record regulatory assets of $10 million and $9 million for CSPCo and OPCo, respectively, for the differential in the approved market price of $53.03 versus the rate paid by Ormet during the first quarter of 2009. These amounts are included in CSPCo’s and OPCo’s FAC phase-in deferral balance of $17 million and $66 million, respectively. See “Ohio Electric Security Plan Filings” section above.
The pricing and deferral authority under the PUCO’s January 2009 approval of the interim arrangement will continue until the 2009-2018 power contract becomes effective. Management cannot predict when or forgo more profitable market-priced off-system sales.if the PUCO will approve the new power contract.
Hurricane Ike – Affecting CSPCo and OPCo
In September 2008, the service territories of CSPCo and OPCo were impacted by strong winds from the remnants of Hurricane Ike. Under the RSP, which was effective in 2008, CSPCo and OPCo incurred approximately $18 million and $13 million, respectively, in incremental distribution operation and maintenance costs related to service restoration efforts. Under the current RSP, CSPCo and OPCo cancould seek a distribution rate adjustment to recover incremental distribution expenses related to major storm service restoration efforts. In September 2008, CSPCo and OPCo established regulatory assets of $17 million and $10 million, respectively, for the incremental distribution operationexpected recovery of the storm restoration costs. In December 2008, CSPCo and maintenance costs relatedOPCo filed with the PUCO a request to major storm service restoration efforts. Theestablish the regulatory assets representunder the excess above the averageterms of the last three yearsRSP, plus accrue carrying costs on the unrecovered balance using CSPCo’s and OPCo’s weighted average cost of capital carrying charge rates. In December 2008, the PUCO subsequently approved the establishment of the regulatory assets but authorized CSPCo and OPCo to record a long-term debt only carrying cost on the regulatory asset. In its order approving the deferrals, the PUCO stated that the mechanism for recovery would be determined in CSPCo’s and OPCo’s next distribution storm expenses excluding Hurricane Ike, which wasrate filing.
In December 2008, the methodology usedConsumers for Reliable Electricity in Ohio filed a request with the PUCO asking for an investigation into the service reliability of Ohio’s investor-owned electric utilities, including CSPCo and OPCo. The investigation request included the widespread outages caused by the September 2008 wind storm. CSPCo and OPCo filed a response asking the PUCO to determinedeny the recoverable amount of storm restoration expenses in the most recent 2006 PUCO storm damage recovery decision. Prior to December 31, 2008, which is the expiration of the RSP, CSPCo and OPCo will file for recovery of the regulatory assets. request.
As a result of the past favorable treatment of storm restoration costs under the RSP and the favorable RSP recovery provisions, which were in effect when the storm occurred and the filings made, management believes the recovery of the regulatory assets is probable. IfHowever, if these regulatory assets are not recoverable,recovered, it would have an adverse effect on future net income and cash flows.
VirginiaTexas Rate Matters
Virginia Base Rate FilingTexas Restructuring – SPP – Affecting APCoSWEPCo
In May 2008, APCo filed an application withAugust 2006, the Virginia SCCPUCT adopted a rule extending the delay in implementation of customer choice in SWEPCo’s SPP area of Texas until no sooner than January 1, 2011. In April 2009, the Texas Senate passed a bill related to increase its base rates by $208 million on an annual basis. The requested increase is based upon a calendar 2007 test year adjusted for changes in revenues, expenses, rate baseSWEPCo’s SPP area of Texas that requires cost of service regulation until certain stages have been completed and capital structure through June 2008. This is consistent with the ratemaking treatment adoptedapproved by the Virginia SCCPUCT such that fair competition is available to all retail customer classes. The bill is expected to be reviewed by the Texas House of Representatives which, if passed, would be sent to the governor of Texas for approval. If the bill is signed, management may be required to re-apply SFAS 71 for the generation portion of SWEPCo’s Texas jurisdiction. The initial reapplication of SFAS 71 regulatory accounting would likely result in APCo’s 2006 base rate case. The proposed revenue requirement reflects a return on equity of 11.75%. Hearings began in October 2008. As permitted under Virginia law, APCo implemented these new base rates, subject to refund, effective October 28, 2008.an extraordinary loss.
In September 2008, the Attorney General’s office filed testimony recommending the proposed $208 million annual increase in base rate be reduced to $133 million. The decrease is principally due to the use of a return on equity approved in the last base rate case of 10% and various rate base and operating income adjustments, including a $25 million proposed disallowance of capacity equalization charges payable by APCo as a deficit member of the FERC approved AEP Power Pool.Stall Unit
In October 2008, the See “Stall Unit” section within “Louisiana Rate Matters” for disclosure.
Turk Plant
See “Turk Plant” section within “Arkansas Rate Matters” for disclosure.
Virginia SCC staff filed testimony recommending the proposed $208 million annual increase in base rate be reduced to $157 million. The decrease is principally due to the use of a recommended return on equity of 10.1%. In October 2008, hearings were held in which APCo filed a $168 million settlement agreement which was accepted by all parties except one industrial customer. APCo expects to receive a final order from the Virginia SCC in November 2008.Rate Matters
Virginia E&R Costs Recovery Filing – Affecting APCo
As of September 2008,Due to the recovery provisions in Virginia law, APCo has $118 million of deferred Virginiabeen deferring incremental E&R costs (excluding $25 million of unrecognizedas incurred, excluding the equity carrying costs). The $118 million consists of $6 million already approved by the Virginia SCC to be collected during the fourth quarter 2008, $54 million relating to APCo’s May 2008 filing for recovery in 2009, and $58 million, representing costs deferred in 2008 to date, to be included (along with the fourth quarter 2008 E&R deferrals) in the 2009 E&R filing, to be collected in 2010.
In September 2008, a settlement was reached between the parties to the 2008 filing and a stipulation agreement (stipulation) was submitted to the hearing examiner. The stipulation provides for recovery of $61 million of incremental E&R costs in 2009 which is an increase of $12 million over the level of E&R surcharge revenues being collected in 2008. The stipulation included an unfavorable $1 million adjustment related to certain costs considered not recoverable E&R costs and recovery of $4.5 million representing one-half of a $9 million Virginia jurisdictional portion of NSR settlement expenses recorded in 2007. In accordance with the stipulation, APCo will request the remaining one-half of the $9 million of NSR settlement expenses in APCo’s 2009 E&R filing. The stipulation also specifies that APCo will remove $3 million of the $9 million of NSR settlement expenses requested to be recovered over 3 years in the current base rate case from the base rate case’s revenue requirement.
In September 2008, the hearing examiner recommended that the Virginia SCC accept the stipulation. As a result, in September 2008, APCo deferred as a regulatory asset $9 million of NSR settlement expenses it had expensed in 2007 that have become probable ofreturn on non-CWIP capital investments, pending future recovery. In October 2008, the Virginia SCC approved thea stipulation agreement to recover $61 million of incremental E&R costs incurred from October 2006 to December 2007 through a surcharge in 2009 which will have a favorable effect on 2009 future cash flows of $61 million and on net income for the previously unrecognized equity portion of the carrying costs of approximately $11 million.
The Virginia E&R cost recovery mechanism under Virginia law ceased effective with costs incurred through December 2008. However, the 2007 amendments to Virginia’s electric utility restructuring law provide for a rate adjustment clause to be requested in 2009 to recover incremental E&R costs incurred through December 2008. Under this amendment, APCo will request recovery of its 2008 unrecovered incremental E&R costs in a planned May 2009 filing. As of March 31, 2009, APCo has $109 million of deferred Virginia incremental E&R costs (excluding $22 million of unrecognized equity carrying costs). The $109 million consists of $6 million of over recovery of costs collected from the 2008 surcharge, $36 million approved by the Virginia SCC related to the 2009 surcharge and $79 million, representing costs deferred during 2008, to be included in the 2009 E&R filing, for collection in 2010.
If the Virginia SCC were to disallow a material portion of APCo’s 2008 deferral,deferred incremental E&R costs, it would have an adverse effect on future net income and cash flows.
Virginia Fuel ClauseAPCo’s Filings for an IGCC Plant – Affecting APCo
In July 2007,January 2006, APCo filed an application witha petition from the Virginia SCCWVPSC requesting approval of a Certificate of Public Convenience and Necessity (CPCN) to seek an annualized increase, effective September 1, 2007, of $33 million for fuel costs and sharing of off-system sales.construct a 629 MW IGCC plant adjacent to APCo’s existing Mountaineer Generating Station in Mason County, West Virginia.
In FebruaryJune 2007, APCo sought pre-approval from the WVPSC for a surcharge rate mechanism to provide for the timely recovery of pre-construction costs and the ongoing finance costs of the project during the construction period, as well as the capital costs, operating costs and a return on equity once the facility is placed into commercial operation. In March 2008, the Virginia SCC issued an order thatWVPSC granted APCo the CPCN to build the plant and approved a reduced fuel factor effectivethe requested cost recovery. In March 2008, various intervenors filed petitions with the February 2008 billing cycle. The order terminatedWVPSC to reconsider the off-system sales margin rider and approved a 75%-25% sharing of off-system sales margins between customers and APCo effective September 1, 2007 as required byorder. No action has been taken on the re-regulation legislation in Virginia. The order also allows APCo to include in its monthly under/over recovery deferrals the Virginia jurisdictional share of PJM transmission line loss costs from June 2007. The adjusted factor increases annual fuel clause revenues by $4 million. The order authorized the Virginia SCC staff and other parties to make specific recommendations to the Virginia SCC in APCo’s next fuel factor proceeding to ensure accurate assignment of the prudently incurred PJM transmission line loss costs to APCo’s Virginia jurisdictional operations. Management believes the incurred PJM transmission line loss costs are prudently incurred and are being properly assigned to APCo’s Virginia jurisdictional operations.
In July 2008, APCo filed its next fuel factor proceeding with the Virginia SCC and requested an annualized increase of $132 million effective September 1, 2008. The increase primarily relates to increases in coal costs. In August 2008, the Virginia SCC issued an order to allow APCo to implement the increased fuel factor on an interim basisrequests for services rendered after August 2008. In September 2008, the Virginia SCC staff filed testimony recommending a lower fuel factor which will result in an annualized increase of $117 million, which includes the PJM transmission line loss costs, instead of APCo’s proposed $132 million. In October 2008, the Virginia SCC ordered an annualized increase of $117 million for services rendered on and after October 20, 2008.
APCo’s Virginia SCC Filing for an IGCC Plant – Affecting APCorehearing.
In July 2007, APCo filed a request with the Virginia SCC for a rate adjustment clause to recover initial costs associated with a proposed 629 MW IGCC plant to be constructed in Mason County, West Virginia adjacent to APCo’s existing Mountaineer Generating Station for an estimated cost of $2.2 billion.plant. The filing requested recovery of an estimated $45 million over twelve months beginning January 1, 2009 including2009. The $45 million included a return on projected CWIP and development, design and planning pre-construction costs incurred from July 1, 2007 through December 31, 2009. APCo also requested authorization to defer a returncarrying cost on deferred pre-construction costs incurred beginning July 1, 2007 until such costs are recovered. Through September 30, 2008, APCo has deferred for future recovery pre-construction IGCC costs of approximately $9 million allocated to Virginia jurisdictional operations.
The Virginia SCC issued an order in April 2008 denying APCo’s requests, stating the beliefin part, upon its finding that the estimated cost of the plant was uncertain and may be significantly understated.escalate. The Virginia SCC also expressed concern that the $2.2 billion estimated cost did not include a retrofitting of carbon capture and sequestration facilities. In AprilJuly 2008, based on the unfavorable order received in Virginia, the WVPSC issued a notice seeking comments from parties on how the WVPSC should proceed. Various parties, including APCo, filed a petitioncomments but the WVPSC has not taken any action.
Through March 31, 2009, APCo deferred for reconsideration in Virginia. In May 2008, thefuture recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia SCC denied APCo’s requestjurisdiction, approximately $2 million applicable to reconsider its previous ruling. FERC jurisdiction and approximately $9 million allocated to its Virginia jurisdiction.
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 expenseexpenses being incurred and certification of the IGCC plant prior to July 2010.
Although management continues to pursue the construction of the IGCC plant, APCo will not start construction of the IGCC plant until sufficient assurance of cost recovery exists. If the 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.
Mountaineer Carbon Capture Project – Affecting APCo
In January 2008, APCo and ALSTOM Power Inc. (Alstom), an unrelated third party, entered into an agreement to jointly construct a CO2 capture demonstration facility. APCo and Alstom will each own part of the CO2 capture facility. APCo will also construct and own the necessary facilities to store the CO2. RWE AG, a German electric power and natural gas public utility, is participating in the project and is providing some funding to offset APCo's costs. APCo’s estimated cost for its share of the facilities is $76$73 million. Through September 30, 2008,March 31, 2009, APCo incurred $13$45 million in capitalized project costs which isare included in Regulatory Assets. APCo earns a return on the capitalized project costs incurred through June 30, 2008, as a result of the base rate case settlement approved by the Virginia SCC in November 2008. APCo plans to seek recovery for the CO2 capture and storage project costs including a return on the additional investment since June 2008 in its next Virginia and West Virginia base rate filings which are expected to be filed in 2009. APCo is presently seeking a return on the capitalized project costs in its current Virginia base rate filing. The Attorney General has recommended that the project costs should be shared by all affiliated operating companies with coal-fired generation plants. If a significant portion of the deferred project costs are excluded from base rates and ultimately disallowed in future Virginia and/or West Virginia rate proceedings, it could have an adverse effect on future net income and cash flows.
West Virginia Rate Matters
APCo’s 20082009 Expanded Net Energy Cost (ENEC) Filing – Affecting APCo
In February 2008,March 2009, APCo filed an annual ENEC filing with the WVPSC for an increase of approximately $140$398 million including a $122 million increase in the ENEC, a $15 million increase in construction cost surchargesfor incremental fuel, purchased power and $3 million of reliability expenditures,environmental compliance project expenses, to become effective July 2008. 2009. Within the filing, APCo requested the WVPSC to allow APCo to temporarily adopt a modified ENEC mechanism due to the distressed economy. The proposed modified ENEC mechanism provides that all deferred ENEC amounts as of June 30, 2009 be recovered over a five-year period beginning in July 2009. The mechanism also extends cost projections out for a period of three years through June 30, 2012 and provides for three annual increases to recover projected future ENEC cost increases. APCo is also requesting all deferred amounts that exceed the deferred amounts that would have existed under the traditional ENEC mechanism be subject to a carrying charge based upon APCo’s weighted average cost of capital. As filed, the modified ENEC mechanism would produce three annual increases, including carrying charges, of $170 million, $149 million and $155 million, effective July 2009, 2010 and 2011, respectively.
In June 2008,March 2009, the WVPSC issued an order approving a joint stipulation and settlement agreement grantingsuspending the rate increases, effective July 2008, of approximately $95 million, including a $79 million increase in the ENEC, a $13 million increase in construction cost surcharges and $3 million of reliability expenditures. The ENEC is an expanded form of fuel clause mechanism, which includes all energy-related costs including fuel, purchased power expenses, off-system sales credits, PJM costs associated with transmission line losses due to the implementation of marginal loss pricing and other energy/transmission items.
The ENEC is subject to a true-up to actual costs and should have no earnings effect if actual costs exceed the recoveries due to the deferral of any over/under-recovery of ENEC costs. The construction cost and reliability surcharges are not subject to a true-up to actual costs and could impact future net income and cash flows.
APCo’s West Virginia IGCC Plant Filing – Affecting APCo
request until December 2009. In January 2006,April 2009, APCo filed a petition with the WVPSC requesting itsmotion for approval of a Certificatean interim rate increase of Public Convenience$162 million, effective July 2009 and Necessity (CCN)subject to construct a 629 MW IGCC plant adjacent to APCo’s existing Mountaineer Generating Station in Mason County, West Virginia.
In June 2007, APCo filed testimony withrefund pending the WVPSC supporting the requests for a CCN and for pre-approval of a surcharge rate mechanism to provide for the timely recovery of both pre-construction costs and the ongoing finance costsfinal adjudication of the project during the construction period as well as the capital costs, operating costs and a return on equity once the facility is placed into commercial operation.ENEC by December 2009. In March 2008,April 2009, the WVPSC granted intervention to several parties and heard oral arguments from APCo and intervenors on the CCN to build the plant and the request for cost recovery. Also, in March 2008, various intervenors filed petitions withrequested interim ENEC filing. If the WVPSC were to reconsider the order. No action has been taken on the requests for rehearing. At the timedisallow a material portion of the filing, the cost of the plant was estimated at $2.2 billion. As of September 30, 2008, the estimated cost of the plant has continued to significantly increase. In July 2008, based on the unfavorable order received in Virginia, the WVPSC issued a notice seeking comments from parties on how the WVPSC should proceed. See the “APCo’s Virginia SCC Filing for an IGCC Plant” section above. Through September 30, 2008, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to the West Virginia jurisdiction and approximately $2 million applicable to the FERC jurisdiction. In July 2008, the IRS allocated $134 million in future tax credits to APCo for the planned IGCC plant. Although management continues to pursue the ultimate construction of the IGCC plant, APCo will not start construction of the IGCC plant until sufficient assurance of cost recovery exists. If the 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,APCo’s requested increase, it would have an adverse effect on future net income and cash flows.
APCo’s Filings for an IGCC Plant – Affecting APCo
See “APCo’s Filings for an IGCC Plant” section within “Virginia Rate Matters” for disclosure.
Mountaineer Carbon Capture Project – Affecting APCo
See “Mountaineer Carbon Capture Project” section within “Virginia Rate Matters” for disclosure.
Indiana Rate Matters
Indiana Base Rate Filing – Affecting I&M
In a January 2008 filing with the IURC, updated in the second quarter of 2008, I&M requested an increase in its Indiana base rates of $80 million including a return on equity of 11.5%. The base rate increase includes theincluded a $69 million annual reduction in depreciation expense previously approved by the IURC and implemented for accounting purposes effective June 2007. The depreciation reduction will no longer favorably impact earnings and will adversely affect cash flows when tariff rates are revised to reflect the effect of the depreciation expense reduction. The filing also requests trackers for certain variable components of the cost of service including recently increased PJM costs associated with transmission line losses due to the implementation of marginal loss pricing and other RTO costs, reliability enhancement costs, demand side management/energy efficiency costs, off-system sales margins and environmental compliance costs. The trackers would initially increase annual revenues by an additional $45 million.In addition, I&M proposesproposed to share with ratepayers,customers, through a proposed tracker, 50% of off-system sales margins initially estimated to be $96 million annually with a guaranteed credit to customers of $20 million.
In SeptemberDecember 2008, I&M and all of the Indiana Officeintervenors jointly filed a settlement agreement with the IURC proposing to resolve all of Utility Consumer Counselor (OUCC) and the Industrial Customer Coalition filed testimony recommendingissues in the case. The settlement agreement incorporated the $69 million annual reduction in revenues from depreciation rate reduction in the development of the agreed to revenue increase of $44 million including a $14$22 million and $37 million decreaseincrease in revenue respectively. Twofrom base rates with an authorized return on equity of 10.5% and a $22 million initial increase in tracker revenue for PJM, net emission allowance and DSM costs. The agreement also establishes an off-system sales sharing mechanism and other intervenors filed testimony on limited issues. The OUCC andprovisions which include continued funding for the Industrial Customer Coalition recommended thateventual decommissioning of the Cook Nuclear Plant. In March 2009, the IURC reduceapproved the ROE proposed by I&M, reduce or limitsettlement agreement, with modifications, that provides for an annual increase in revenues of $42 million including a $19 million increase in revenue from base rates, net of the depreciation rate reduction, and a $23 million increase in tracker revenue. The IURC order removed base rate recovery of the DSM costs but established a tracker with an initial zero amount for DSM costs, adjusted the sharing of off-system sales margin sharing, denymargins to 50% above the $37.5 million included in base rates and approved the recovery of reliability enhancement$7.3 million of previously expensed NSR and OPEB costs and rejectwhich favorably affected first quarter of 2009 net income. In addition, the proposed environmental compliance cost recovery trackers. In October 2008,IURC order requires I&M filed testimony rebuttingto review and file a final report by December 2009 on the recommendationseffectiveness of the OUCC. Hearings are scheduled for December 2008. A decision is expected from the IURC by June 2009.Interconnection Agreement including I&M’s relationship with PJM.
Michigan Rate Matters
Michigan RestructuringRockport and Tanners Creek Plants – Affecting I&M
Although customer choice commencedIn January 2009, I&M filed a petition with the IURC requesting approval of a Certificate of Public Convenience and Necessity (CPCN) to use advanced coal technology which would allow I&M to reduce airborne emissions of NOx and mercury from its existing coal-fired steam electric generating units at the Rockport and Tanners Creek Plants. In addition, the petition is requesting approval to construct and recover the costs of selective non-catalytic reduction (SNCR) systems at the Tanners Creek Plant and to recover the costs of activated carbon injection (ACI) systems on both generating units at the Rockport Plant. I&M is requesting to depreciate the ACI systems over an accelerated 10-year period and the SNCR systems over the remaining useful life of the Tanners Creek generating units. I&M requested the IURC to approve a rate adjustment mechanism of unrecovered carrying costs during construction and a return on investment, depreciation expense and operation and maintenance costs, including consumables and new emission allowance costs, once the projects are placed in service. I&M also requested the IURC to authorize the deferral of the cost of service of these projects and carrying costs until such costs are recognized in the requested rate adjustment mechanism. Through March 2009, I&M incurred $9 million and $6 million in capitalized project costs related to the Rockport and Tanners Creek Plants, respectively, which are included in Construction Work in Progress. In March 2009, the IURC issued a prehearing conference order setting a procedural schedule. Since the Indiana base rate order included recovery of emission allowance costs, that portion of this request will be eliminated. An order is expected by the third quarter of 2009. Management is unable to predict the outcome of this petition.
Indiana Fuel Clause Filing – Affecting I&M
In January 2009, I&M filed with the IURC an application to increase its fuel adjustment charge by approximately $53 million for April through September 2009. The filing included an under-recovery for the period ended November 2008, mainly as a result of the extended outage of the Cook Plant Unit 1 (Unit 1) due to fire damage to the main turbine and generator, increased coal prices and a projection for the future period of fuel costs including Unit 1 fire related outage replacement power costs. The filing also included an adjustment, beginning coincident with the receipt of insurance proceeds, to reduce the incremental fuel cost of replacement power with a portion of the insurance proceeds from the Unit 1 accidental outage policy. See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4. I&M reached an agreement in February 2009 with intervenors, which was approved by the IURC in March 2009, to collect the under-recovery over twelve months instead of over six months as proposed. Under the order, the fuel factor will go into effect, subject to refund, and a subdocket will be established to consider issues relating to the Unit 1 fire outage, the use of the insurance proceeds and I&M’s Michigan customers on January 1, 2002, I&M’s ratesfuel procurement practices. The order provides for generation in Michigan continuedthe fire outage issues to be cost-based regulated because none of I&M's customers electedresolved subsequent to change suppliers and no alternative electric suppliers were registeredthe date Unit 1 returns to compete in I&M's Michigan service, territory. Inwhich if temporary repairs are successful, could occur as early as October 2008,2009. Management cannot predict the Governor of Michigan signed legislation to limit customer choice load to no more than 10%outcome of the annual retail load forpending proceedings, including the preceding calendar yeartreatment of the insurance proceeds, and to require the remaining 90% of annual retail loadwhether any fuel clause revenues will have to be phased into cost-based rates. The new legislation also requires utilities to meet certain energy efficiency and renewable portfolio standards and requiresrefunded as a result.
Michigan Rate Matters – Affecting I&M
In March 2009, I&M filed with the Michigan Public Service Commission its 2008 power supply cost recovery reconciliation. The filing also included an adjustment to reduce the incremental fuel cost of meeting those standards.replacement power with a portion of the insurance proceeds from the Cook Plant Unit 1 accidental outage policy. See “Cook Plant Unit 1 Fire and Shutdown” section of Note 4. Management continuesis unable to conclude that I&M's rates for generation in Michigan are cost-based regulated.predict the outcome of this proceeding and its possible effect on future net income and cash flows.
Oklahoma Rate Matters
PSO Fuel and Purchased Power – Affecting PSO
The Oklahoma Industrial Energy Consumers appealed an ALJ recommendation2006 and Prior Fuel and Purchased Power
Proceedings addressing PSO’s historic fuel costs from 2001 through 2006 remain open at the OCC due to the issue of the allocation of off-system sales margins among the AEP operating companies in June 2008 regardingaccordance with a pendingFERC-approved allocation agreement.
In 2002, PSO under-recovered $42 million of fuel case involving thecosts resulting from a reallocation of $42 millionamong AEP West companies of purchased power costs among AEP West companies infor periods prior to 2002. The Oklahoma Industrial Energy Consumers requested that PSO be required to refund this $42 million of reallocated purchased power costs through its fuel clause. PSO had recovered the $42 million by offsetting it against an existing fuel over-recovery during the period June 2007 through May 2008. In June 2008, the Oklahoma Industrial Energy Consumers (OIEC) appealed an ALJ recommendation that concluded it was a FERC jurisdictional matter which allowed PSO to retain the $42 million it recovered from ratepayers. The OIEC requested that PSO be required to refund the $42 million through its fuel clause. In August 2008, the OCC heard the OIEC appeal and a decision is pending.
In February 2006, the OCC enacted a rule, requiring the OCC staff to conduct prudence reviews For further discussion and estimated effect on PSO’s generation and fuel procurement processes, practices and costs on a periodic basis. PSO filed testimony in June 2007 covering a prudence review for the year 2005. The OCC staff and intervenors filed testimony in September 2007, and hearings were held in November 2007. The only major issue in the proceeding was the alleged under allocation of off-system sales credits under the FERC-approved allocation methodology, which previously was determined not to be jurisdictional to the OCC. Seenet income, see “Allocation of Off-system Sales Margins” section within “FERC Rate Matters”. Consistent with the prior OCC determination, the ALJ found that the OCC lacked authority to alter the FERC-approved allocation methodology and that PSO’s fuel costs were prudent. The intervenors appealed the ALJ recommendation and the OCC heard the appeal in August 2008. In August 2008, the OCC filed a complaint at the FERC alleging that AEPSC inappropriately allocated off-system trading margins between the AEP East companies and the AEP West companies and did not properly allocate off-system trading margins within the AEP West companies.
In November 2007 PSO filed testimony in another proceeding to address its fuel costs for 2006. In April 2008, intervenor testimony was filed again challenging the allocation of off-system sales credits during the portion of the year when the allocation was in effect. Hearings were held in July 2008Fuel and the OCC changed the scope of the proceeding from a prudence review to only a review of the mechanics of the fuel cost calculation. No party contested PSO’s fuel cost calculation. In August 2008, the OCC issued a final order that PSO’s calculations of fuel and purchased power costs were accurate and are consistent with PSO’s fuel tariff.Purchased Power
In September 2008, the OCC initiated a review of PSO’s generation, purchased power and fuel procurement processes and costs for 2007. Under the OCC minimum filing requirements, PSO is required to file testimony and supporting data within 60 days which will occur in the fourth quarter of 2008. Management cannot predict the outcome of the pending fuel and purchased power cost recovery filings or prudence reviews.filings. However, PSO believes its fuel and purchased power procurement practices and costs were prudent and properly incurred and therefore are legally recoverable.
Red Rock Generating Facility – Affecting PSO
In July 2006, PSO announced an agreement with Oklahoma Gas and Electric Company (OG&E) to build a 950 MW pulverized coal ultra-supercritical generating unit. PSO would own 50% of the new unit. Under the agreement, OG&E would manage construction of the plant. OG&E and PSO requested pre-approval to construct the coal-fired Red Rock Generating Facility (Red Rock) and to implement a recovery rider.
In October 2007, the OCC issued a final order approving PSO’s need for 450 MWs of additional capacity by the year 2012, but rejected the ALJ’s recommendation and denied PSO’s and OG&E’s applications for construction pre-approval. The OCC stated that PSO failed to fully study other alternatives to a coal-fired plant. Since PSO and OG&E could not obtain pre-approval to build Red Rock, PSO and OG&E cancelled the third party construction contract and their joint venture development contract. In June 2008, PSO issued a request-for-proposal to meet its capacity and energy needs.
In December 2007, PSO filed an application at the OCC requesting recovery of $21 million in pre-construction costs and contract cancellation fees associated with Red Rock. In March 2008, PSO and all other parties in this docket signed a settlement agreement that provides for recovery of $11 million of Red Rock costs, and provides carrying costs at PSO’s AFUDC rate beginning in March 2008 and continuing until the $11 million is included in PSO’s next base rate case. PSO will recover the costs over the expected life of the peaking facilities at the Southwestern Station, and include the costs in rate base in its next base rate filing. The settlement was filed with the OCC in March 2008. The OCC approved the settlement in May 2008. As a result of the settlement, PSO wrote off $10 million of its deferred pre-construction costs/cancellation fees in the first quarter of 2008. In July 2008, PSO filed a base rate case which included $11 million of deferred Red Rock costs plus carrying charges at PSO’s AFUDC rate beginning in March 2008. See “2008 Oklahoma Base Rate Filing” section below.
Oklahoma 2007 Ice Storms – Affecting PSO
In October 2007, PSO filed with the OCC requesting recovery of $13 million of operation and maintenance expense related to service restoration efforts after a January 2007 ice storm. PSO proposed in its application to establish a regulatory asset of $13 million to defer the previously expensed January 2007 ice storm restoration costs and to amortize the regulatory asset coincident with gains from the sale of excess SO2 emission allowances. In December 2007, PSO expensed approximately $70 million of additional storm restoration costs related to the December 2007 ice storm.
In February 2008, PSO entered into a settlement agreement for recovery of costs from both ice storms. In March 2008, the OCC approved the settlement subject to an audit of the final December ice storm costs filed in July 2008. As a result, PSO recorded an $81 million regulatory asset for ice storm maintenance expenses and related carrying costs less $9 million of amortization expense to offset recognition of deferred gains from sales of SO2 emission allowances. Under the settlement agreement, PSO would apply proceeds from sales of excess SO2 emission allowances of an estimated $26 million to recover part of the ice storm regulatory asset. The settlement also provided for PSO to amortize and recover the remaining amount of the regulatory asset through a rider over a period of five years beginning in the fourth quarter of 2008. The regulatory asset will earn a return of 10.92% on the unrecovered balance.
In June 2008, PSO adjusted its regulatory asset to true-up the estimated costs to actual costs. After the true-up, application of proceeds from to-date sales of excess SO2 emission allowances and carrying costs, the ice storm regulatory asset was $64 million. The estimate of future gains from the sale of SO2 emission allowances has significantly declined with the decrease in value of such allowances. As a result, estimated collections from customers through the special storm damage recovery rider will be higher than the estimate in the settlement agreement. In July 2008, as required by the settlement agreement, PSO filed its reconciliation of the December 2007 storm restoration costs along with a proposed tariff to recover the amounts not offset by the sales of SO2 emission allowances. In September 2008, the OCC staff filed testimony supporting PSO’s filing with minor changes. In October 2008, an ALJ recommended that PSO recover $62 million of the December 2007 storm restoration costs before consideration of emission allowance gains and carrying costs. In October 2008, the OCC approved the filing which allows PSO to recover $62 million of the December 2007 storm restoration costs beginning in November 2008.
2008 Oklahoma Annual Fuel Factor Filing – Affecting PSO
In May 2008, pursuant to its tariff, PSO filed its annual update with the OCC for increases in the various service level fuel factors based on estimated increases in fuel costs, primarily natural gas and purchased power expenses, of approximately $300 million. The request included recovery of $26 million in under-recovered deferred fuel. In June 2008, PSO implemented the fuel factor increase. Because of the substantial increase, the OCC held an administrative proceeding to determine whether the proposed charges were based upon the appropriate coal, purchased gas and purchased power prices and were properly computed. In June 2008, the OCC ordered that PSO properly estimated the increase in natural gas prices, properly determined its fuel costs and, thus, should implement the increase.
2008 Oklahoma Base Rate Filing – Affecting PSO
In July 2008, PSO filed an application with the OCC to increase its base rates by $133 million (later adjusted to $127 million) on an annual basis. PSO recovershas been recovering costs related to new peaking units recently placed into service through thea Generation Cost Recovery Rider (GCRR). UponSubsequent to implementation of the new base rates, the GCRR will terminate and PSO will recover these costs through the new base rates and the GCRR will terminate.rates. Therefore, PSO’s net annual requested increase in total revenues iswas actually $117 million. The requested increase is based upon a test year ended February 29, 2008,million (later adjusted for known and measurable changes through August 2008, which is consistent with the ratemaking treatment adopted by the OCC in PSO’s 2006 base rate case.to $111 million). The proposed revenue requirement reflectsreflected a return on equity of 11.25%. PSO expects hearings to begin
In January 2009, the OCC issued a final order approving an $81 million increase in December 2008PSO’s non-fuel base revenues and newa 10.5% return on equity. The rate increase includes a $59 million increase in base rates and a $22 million increase for costs to become effectivebe recovered through riders outside of base rates. The $22 million increase includes $14 million for purchase power capacity costs and $8 million for the recovery of carrying costs associated with PSO’s program to convert overhead distribution lines to underground service. The $8 million recovery of carrying costs associated with the overhead to underground conversion program will occur only if PSO makes the required capital expenditures. The final order approved lower depreciation rates and also provides for the deferral of $6 million of generation maintenance expenses to be recovered over a six-year period. This deferral was recorded in the first quarter of 2009. In October 2008,Additional deferrals were approved for distribution storm costs above or below the amount included in base rates and for certain transmission reliability expenses. The new rates reflecting the final order were implemented with the first billing cycle of February 2009.
PSO filed an appeal with the Oklahoma Supreme Court challenging an adjustment the OCC staff,made on prepaid pension funding contained within the OCC final order. In February 2009, the Oklahoma Attorney General and several intervenors also filed appeals with the Oklahoma Supreme Court raising several issues. If the Attorney General's office,General and/or the intervenor’s Supreme Court appeals are successful, it could have an adverse effect on future net income and a group of industrial customers filed testimony recommending annual base rate increases of $86 million, $68 million and $29 million, respectively. The differences are principally due to the use of recommended return on equity of 10.88%, 10% and 9.5% by the OCC staff, the Attorney General's office, and a group of industrial customers. The OCC staff and the Attorney General's office recommended $22 million and $8 million, respectively, of costs included in the filing be recovered through the fuel adjustment clause and riders outside of base rates.cash flows.
Louisiana Rate Matters
Louisiana Compliance2008 Formula Rate Filing – Affecting SWEPCo
In connection with SWEPCo’s merger related compliance filings, the LPSC approved a settlement agreement in April 2008 that prospectively resolves all issues regarding claims that SWEPCo had over-earned its allowed return. SWEPCo agreed to a formula rate plan (FRP) with a three-year term. Under the plan, beginning in August 2008, rates shall be established to allow SWEPCo to earn an adjusted return on common equity of 10.565%. The adjustments are standard Louisiana rate filing adjustments.
If in the second and third year of the FRP, the adjusted earned return is within the range of 10.015% to 11.115%, no adjustment to rates is necessary. However, if the adjusted earned return is outside of the above-specified range, an FRP rider will be established to increase or decrease rates prospectively. If the adjusted earned return is less than 10.015%, SWEPCo will prospectively increase rates to collect 60% of the difference between 10.565% and the adjusted earned return. Alternatively, if the adjusted earned return is more than 11.115%, SWEPCo will prospectively decrease rates by 60% of the difference between the adjusted earned return and 10.565%. SWEPCo will not record over/under recovery deferrals for refund or future recovery under this FRP.
The settlement provides for a separate credit rider decreasing Louisiana retail base rates by $5 million prospectively over the entire three-year term of the FRP, which shall not affect the adjusted earned return in the FRP calculation. This separate credit rider will cease effective August 2011.
In addition, the settlement provides for a reduction in generation depreciation rates effective October 2007. SWEPCo deferred as a regulatory liability, the effects of the expected depreciation reduction through July 2008. SWEPCo will amortize this regulatory liability over the three-year term of the FRP as a reduction to the cost of service used to determine the adjusted earned return. In August 2008, the LPSC issued an order approving the settlement.
In April 2008, SWEPCo filed the first FRPformula rate plan (FRP) which would increase its annual Louisiana retail rates by $11 million in August 2008 to earn an adjusted return on common equity of 10.565%. In accordance with the settlement, SWEPCo recorded a $4 million regulatory liability related to the reduction in generation depreciation rates. The amount of the unamortized regulatory liability for the reduction in generation depreciation was $4 million as of September 30, 2008. In August 2008, SWEPCo implemented the FRP rates, subject to refund. No provision for refund has been recorded as SWEPCo believes that the rates as implemented are in compliance with the FRP methodology approved by the LPSC. The LPSC staff reviews SWEPCo’shas not approved the rates being collected. If the rates are not approved as filed, it could have an adverse effect on future net income and cash flows.
2009 Formula Rate Filing – Affecting SWEPCo
In April 2009, SWEPCo filed the second FRP filing andwhich would increase its annual Louisiana retail rates by an additional $4 million in August 2009 pursuant to the production depreciation study.formula rate methodology. SWEPCo believes that the rates as filed are in compliance with the FRP methodology previously approved by the LPSC.
Stall Unit – Affecting SWEPCo
In May 2006, SWEPCo announced plans to build a new intermediate load, 500 MW, natural gas-fired, combustion turbine, combined cycle generating unit (the Stall Unit) at its existing Arsenal Hill Plant location in Shreveport, Louisiana. SWEPCo submitted the appropriate filings to the PUCT, the APSC, the LPSC and the Louisiana Department of Environmental Quality to seek approvals to construct the unit. The Stall Unit is currently estimated to cost $378$385 million, excluding AFUDC, and is expected to be in-service in mid-2010. The Louisiana Department of Environmental Quality issued an air permit for the Stall unit in March 2008.
In March 2007, the PUCT approved SWEPCo’s request for a certificate of necessity for the facility based on a prior cost estimate. In SeptemberJuly 2008, a Louisiana ALJ issued a recommendation that SWEPCo be authorized to construct, own and operate the Stall Unit and recommended that costs be capped at $445 million (excluding transmission). In October 2008, the LPSC approved SWEPCo’s request for certificationissued a final order effectively approving the ALJ recommendation. In December 2008, SWEPCo submitted an amended filing seeking approval from the APSC to construct the Stall Unit.unit. The APSC has not established a procedural schedule at this time. The Louisiana Department of Environmental Quality issued an air permit for the unitstaff filed testimony in March 2008. 2009 supporting the approval of the plant. The APSC staff also recommended that costs be capped at $445 million (excluding transmission). A hearing that had been scheduled for April 2009 was cancelled and the APSC will issue its decision based on the amended application and prefiled testimony.
If SWEPCo does not receive appropriate authorizations and permits to build the Stall Unit, SWEPCo would seek recovery of the capitalized pre-constructionconstruction costs including any cancellation fees. As of September 30, 2008,March 31, 2009, SWEPCo has capitalized pre-constructionconstruction costs of $158$291 million (including AFUDC) and has contractual construction commitments of an additional $145$74 million. As of September 30, 2008,March 31, 2009, if the plant had been cancelled, cancellation fees of $61$40 million would have been required in order to terminate thesethe construction commitments. If SWEPCo cancels the plant and 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.
Turk Plant – Affecting SWEPCo
See “Turk Plant” section within Arkansas“Arkansas Rate MattersMatters” for disclosure.
Arkansas Rate Matters
Turk Plant – Affecting SWEPCo
In August 2006, SWEPCo announced plans to build the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas. Ultra-supercritical technology uses higher temperatures and higher pressures to produce electricity more efficiently thereby using less fuel and providing substantial emissions reductions. SWEPCo submitted filings with the APSC, the PUCT and the LPSC seeking certification of the plant. SWEPCo will own 73% of the Turk Plant and will operate the facility. During 2007, SWEPCo signed joint ownership agreements with the Oklahoma Municipal Power Authority (OMPA), the Arkansas Electric Cooperative Corporation (AECC) and the East Texas Electric Cooperative (ETEC) for the remaining 27% of the Turk Plant. During 2007, OMPA exercised its participation option. During the first quarter of 2009, AECC and ETEC exercised their participation options and paid SWEPCo $104 million. SWEPCo recorded a $2.2 million gain from the transactions. The Turk Plant is currently estimated to cost $1.5$1.6 billion, excluding AFUDC, with SWEPCo’s portion estimated to cost $1.1$1.2 billion. If approved on a timely basis, the plant is expected to be in-service in 2012.
In November 2007, the APSC granted approval to build the plant.Turk Plant. Certain landowners filed a notice of appealhave appealed the APSC’s decision 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 $1.5previously estimated $1.522 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 emissionsemission costs exceed the restrictions, it could have a material adverse impacteffect 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.
A request to stop pre-construction activities at the site was filed in federal court by Arkansas landowners. 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 2009, SWEPCo is also working withfiled a motion to dismiss the appeal. In March 2009, the motion was granted.
In November 2008, SWEPCo received the required air permit approval from the Arkansas Department of Environmental Quality forand commenced construction. In December 2008, Arkansas landowners filed an appeal with the approvalArkansas Pollution Control and Ecology Commission (APCEC) which caused construction of the Turk Plant to halt until the APCEC took further action. In December 2008, SWEPCo filed a request with the APCEC to continue construction of the Turk Plant and the APCEC ruled to allow construction to continue while an appeal of the Turk Plant’s permit is heard. Hearings on the air permit andappeal is scheduled for June 2009. SWEPCo is also working with the U.S. Army Corps of Engineers for the approval of a wetlands and stream impact permit. OnceIn March 2009, 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 denialreported to the U.S. CourtArmy Corps of Appeals.Engineers a potential wetlands impact on approximately 2.5 acres at the Turk Plant. The U.S. Army Corps of Engineers directed SWEPCo to cease further work impacting the wetland areas. Construction has continued on other areas of the Turk Plant. The impact on the construction schedule and workforce is currently being evaluated by management.
In January 2008 and July 2008, SWEPCo filed Certificate of Environmental Compatibility and Public Need (CECPN) 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. TheIn June 2008, the landowner filed an appeal to the Arkansas State Court of Appeals in June 2008.requesting to re-litigate Turk Plant issues. SWEPCo responded and the appeal was dismissed. In January 2009, the APSC approved the CECPN applications.
The Arkansas Governor’s Commission on Global Warming is scheduled to issueissued its final report to the Governor by November 1,governor in October 2008. The Commission was established to set a global warming pollution reduction goal together with a strategic plan for implementation in Arkansas. The Commission’s final report included a recommendation that the Turk Plant employ post combustion carbon capture and storage measures as soon as it starts operating. If legislation is passed as a result of the findings in the Commission’s report, it could impact SWEPCo’s proposal to build and operate 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 paidcosts incurred plus related shutdown 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,March 31, 2009, SWEPCo has capitalized approximately $448$480 million of expenditures (including AFUDC) and has significant contractual construction commitments for an additional $771$655 million. As of September 30, 2008,March 31, 2009, if the plant had been cancelled, SWEPCo would have incurred cancellation fees of $61$100 million. 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.
Arkansas Base Rate Filing – Affecting SWEPCo
In February 2009, SWEPCo filed an application with the APSC for a base rate increase of $25 million based on a requested return on equity of 11.5%. SWEPCo also requested a separate rider to recover financing costs related to the construction of the Stall and Turk generating facilities. These financing costs are currently being capitalized as AFUDC in Arkansas. A decision is not expected until the fourth quarter of 2009 or the first quarter of 2010.
Stall Unit – Affecting SWEPCo
See “Stall Unit” section within Louisiana“Louisiana Rate MattersMatters” for disclosure.
FERC Rate Matters
Regional Transmission Rate Proceedings at the FERC – Affecting APCo, CSPCo, I&M and OPCo
SECA Revenue Subject to Refund
Effective December 1, 2004, AEP eliminated transaction-based through-and-out transmission service (T&O) charges in accordance with FERC orders and collected, at the FERC’s direction, load-based charges, referred to as RTO SECA, to partially mitigate the loss of T&O revenues on a temporary basis through March 31, 2006. Intervenors objected to the temporary SECA rates, raising various issues. As a result, the FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund. The AEP East companies paid SECA rates to other utilities at considerably lesser amounts than they collected. If a refund is ordered, the AEP East companies would also receive refunds related to the SECA rates they paid to third parties. The AEP East companies recognized gross SECA revenues of $220 million from December 2004 through March 2006 when the SECA rates terminated leaving the AEP East companies and ultimately their internal load retail customers to make up the short fall in revenues. APCo’s, CSPCo’s, I&M’s and OPCo’s portions of recognized gross SECA revenues are as follows:
Company | | (in millions) | |
APCo | | $ | 70.2 | |
CSPCo | | | 38.8 | |
I&M | | | 41.3 | |
OPCo | | | 53.3 | |
In August 2006, a FERC ALJ issued an initial decision, finding that the rate design for the recovery of SECA charges was flawed and that a large portion of the “lost revenues” reflected in the SECA rates should not have been recoverable. The ALJ found that the SECA rates charged were unfair, unjust and discriminatory and that new compliance filings and refunds should be made. The ALJ also found that the unpaid SECA rates must be paid in the recommended reduced amount.
In September 2006, AEP filed briefs jointly with other affected companies noting exceptions to the ALJ’s initial decision and asking the FERC to reverse the decision in large part. Management believes, based on advice of legal counsel, that the FERC should reject the ALJ’s initial decision because it contradicts prior related FERC decisions, which are presently subject to rehearing. Furthermore, management believes the ALJ’s findings on key issues are largely without merit. AEP and SECA ratepayers haveare engaged in settlement discussions in an effort to settle the SECA issue. However, if the ALJ’s initial decision is upheld in its entirety, it could result in a disallowance of a large portion onof any unsettled SECA revenues.
During 2006, basedBased on anticipated settlements, the AEP East companies provided reserves for net refunds for current and future SECA settlements totaling $37$39 million and $5 million in 2006 and 2007, respectively, applicable to a total of $220 million of SECA revenues. APCo’s, CSPCo’s, I&M’s and OPCo’s portions of the provision are as follows:
| | 2007 | | | 2006 | |
Company | | (in millions) | |
APCo | | $ | 1.7 | | | $ | 12.0 | |
CSPCo | | | 0.9 | | | | 6.7 | |
I&M | | | 1.0 | | | | 7.0 | |
OPCo | | | 1.3 | | | | 9.1 | |
| | 2007 | | | 2006 | |
Company | | (in millions) | |
APCo | | $ | 1.7 | | | $ | 12.4 | |
CSPCo | | | 0.9 | | | | 6.9 | |
I&M | | | 1.0 | | | | 7.3 | |
OPCo | | | 1.3 | | | | 9.4 | |
In February 2009, a settlement agreement was approved by the FERC resulting in the completion of a $1 million settlement applicable to $20 million of SECA revenue. Including this most recent settlement, AEP has completed settlements totaling $7$10 million applicable to $75$112 million of SECA revenues. TheAs of March 31, 2009, there were no in-process settlements. APCo’s, CSPCo’s, I&M’s and OPCo’s reserve balance in the reserve for future settlements as of September 2008 was $35 million. In-process settlements total $3 million applicable to $37 million of SECA revenues. Management believes that the available $32 million of reserves for possible refunds are sufficient to settle the remaining $108 million of contested SECA revenues.at March 31, 2009 was:
| | March 31, 2009 | |
Company | | (in millions) | |
APCo | | $ | 10.7 | |
CSPCo | | | 5.9 | |
I&M | | | 6.3 | |
OPCo | | | 8.2 | |
If the FERC adopts the ALJ’s decision and/or AEP cannot settle all of the remaining unsettled claims within the remaining amount reserved for refund, it will have an adverse effect on future net income and cash flows. Based on advice of external FERC counsel, recent settlement experience and the expectation that most of the unsettled SECA revenues will be settled, management believes that the remainingavailable reserve of $32$34 million is adequate to cover allsettle the remaining settlements.$108 million of contested SECA revenues. If the remaining unsettled SECA claims are settled for considerably more than the to-date settlements or if the remaining unsettled claims are awarded a refund by the FERC greater than the remaining reserve balance, it could have an adverse effect on net income. Cash flows will be adversely impacted by any additional settlements or ordered refunds. However, management cannot predict the ultimate outcome of ongoing settlement discussions or future FERC proceedings or court appeals, if necessary.any.
The FERC PJM Regional Transmission Rate Proceeding
With the elimination of T&O rates, the expiration of SECA rates and after considerable administrative litigation at the FERC in which AEP sought to mitigate the effect of the T&O rate elimination, the FERC failed to implement a regional rate in PJM. As a result, the AEP East companies’ retail customers incur the bulk of the cost of the existing AEP east transmission zone facilities. However, the FERC ruled that the cost of any new 500 kV and higher voltage transmission facilities built in PJM would be shared by all customers in the region. It is expected that most of the new 500 kV and higher voltage transmission facilities will be built in other zones of PJM, not AEP’s zone. The AEP East companies will need to obtain state regulatory approvals for recovery of any costs of new facilities that are assigned to them. AEP requested rehearing of this order, which the FERC denied.them by PJM. In February 2008, AEP filed a Petition for Review of the FERC orders in this case in the United States Court of Appeals. Management cannot estimate at this time what effect, if any, this order will have on the AEP East companies’ future construction of new transmission facilities, net income and cash flows.
The AEP East companies filed for and in 2006 obtained increases in their wholesale transmission rates to recover lost revenues previously applied to reduce those rates. AEP has also sought and received retail rate increases in Ohio, Virginia, West Virginia and Kentucky. In January and March 2009, AEP received retail rate increases in Tennessee and Indiana, respectively, that recognized the higher retail transmission costs resulting from the loss of wholesale transmission revenues from T&O transactions. As a result, AEP is now recovering approximately 80%98% of the lost T&O transmission revenues. AEP received net SECA transmission revenues of $128 millionThe remaining 2% is being incurred by I&M until it can revise its rates in 2005. I&M requested recovery of these lost revenues in its Indiana rate filing in January 2008 but does not expectMichigan to commence recovering the new rates until early 2009. Future net income and cash flows will continue to be adversely affected in Indiana and Michigan until the remaining 20% ofrecover the lost T&O transmission revenues are recovered in retail rates.revenues.
The FERC PJM and MISO Regional Transmission Rate Proceeding
In the SECA proceedings, the FERC ordered the RTOs and transmission owners in the PJM/MISO region (the Super Region) to file, by August 1, 2007, a proposal to establish a permanent transmission rate design for the Super Region to be effective February 1, 2008. All of the transmission owners in PJM and MISO, with the exception of AEP and one MISO transmission owner, elected to support continuation of zonal rates in both RTOs. In September 2007, AEP filed a formal complaint proposing a highway/byway rate design be implemented for the Super Region where users pay based on their use of the transmission system. AEP argued the use of other PJM and MISO facilities by AEP is not as large as the use of AEP transmission by others in PJM and MISO. Therefore, a regional rate design change is required to recognize that the provision and use of transmission service in the Super Region is not sufficiently uniform between transmission owners and users to justify zonal rates. In January 2008, the FERC denied AEP’s complaint. AEP filed a rehearing request with the FERC in March 2008. Should this effort beIn December 2008, the FERC denied AEP’s request for rehearing. In February 2009, AEP filed an appeal in the U.S. Court of Appeals. If the court appeal is successful, earnings could benefit for a certain period of time due to regulatory lag until the AEP East companies reduce future retail revenues in their next fuel or base rate proceedings.proceedings to reflect the resultant additional transmission cost reductions. Management is unable to predict the outcome of this case.
PJM Transmission Formula Rate Filing – Affecting APCo, CSPCo, I&M and OPCo
In July 2008, AEP filed an application with the FERC to increase its rates for wholesale transmission service within PJM by $63 million annually. The filing seeks to implement a formula rate allowing annual adjustments reflecting future changes in AEP'sthe AEP East companies' cost of service. In September 2008, the FERC issued an order conditionally accepting AEP’s proposed formula rate, subject to a compliance filing, established a settlement proceeding with an ALJ, and delayed the requested October 2008 effective date for five months. The requested increase, would resultwhich the AEP East companies began billing in additional annual revenuesApril 2009 for service as of approximately $9March 1, 2009, will produce a $63 million annualized increase in revenues. Approximately $8 million of the increase will be collected from nonaffiliated customers within PJM. The remaining $54$55 million requested would be billed to the AEP East companies tobut would be recovered inoffset by compensation from PJM for use of the AEP East companies’ transmission facilities so that retail rates. Retail rates for jurisdictions other than Ohio are not affected until the next base rate filing at FERC.directly affected. Retail rates for CSPCo and OPCo would be adjustedincreased through the Transmission Cost Recovery Rider (TCRR)TCRR totaling approximately $10 million and $12$13 million, respectively. The TCRR includes a true-up mechanism so CSPCo’s and OPCo’s net income will not be adversely affected by a FERC ordered transmission rate increase. Other jurisdictions would be recoverable on a lag basis as base rates are changed.In October 2008, AEP requested an effective date of October 1, 2008. In September 2008,filed the FERC issued an order conditionally accepting AEP’s proposed formula rate, subject to arequired compliance filing, suspendedand began settlement discussions with the intervenors and FERC staff. The settlement discussions are currently ongoing. Under the formula, rates will be updated effective date until MarchJuly 1, 2009, and established a settlement proceedingeach year thereafter. Also, beginning with the July 1, 2010 update, the rates each year will include an ALJ.adjustment to true-up the prior year's collections to the actual costs for the prior year. Management is unable to predict the outcome of the settlement discussions or any further proceedings that might be necessary if settlement discussions are not successful.
Allocation of Off-system Sales Margins – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo
In August 2008, the OCC filed a complaint at the FERC alleging that AEP inappropriately allocated off-system sales margins between the AEP East companies and the AEP West companies and did not properly allocate off-system sales margins within the AEP West companies. The PUCT, the APSC and the Oklahoma Industrial Energy Consumers intervened in this filing. In November 2008, the FERC issued a final order concluding that AEP inappropriately deviated from off-system sales margin allocation methods in the SIA and the CSW Operating Agreement for the period June 2000 through March 2006. The FERC ordered AEP to recalculate and reallocate the off-system sales margins in compliance with the SIA and to have the AEP East companies issue refunds to the AEP West companies. Although the FERC determined that AEP deviated from the CSW Operating Agreement, the FERC determined the allocation methodology was reasonable. The FERC ordered AEP to submit a revised CSW Operating Agreement for the period June 2000 to March 2006. In December 2008, AEP filed a motion for rehearing and a revised CSW Operating Agreement for the period June 2000 to March 2006. The motion for rehearing is still pending. In January 2009, AEP filed a compliance filing with the FERC and refunded approximately $250 million from the AEP East companies to the AEP West companies. The AEP West companies shared a portion of such revenues with their wholesale and retail customers during the period June 2000 to March 2006. In December 2008, the AEP West companies recorded a provision for refund. In January 2009, SWEPCo refunded approximately $13 million to FERC wholesale customers. In February 2009, SWEPCo filed a settlement agreement with the PUCT that provides for the Texas retail jurisdiction amount to be included in the March 2009 fuel cost report submitted to the PUCT. PSO began refunding approximately $54 million plus accrued interest to Oklahoma retail customers through the fuel adjustment clause over a 12-month period beginning with the March 2009 billing cycle. SWEPCo is working with the APSC and the LPSC to determine the effect the FERC order will have on retail rates. Management cannot predict the outcome of the requested FERC rehearing proceeding or any future state regulatory proceedings but believes the AEP West companies’ provision for refund regarding future regulatory proceedings is adequate.
SPP Transmission Formula Rate Filing – Affecting PSO and SWEPCo
In June 2007, AEPSC filed revised tariffs to establish an up-to-date revenue requirement for SPP transmission services over the facilities owned by PSO and SWEPCo and to implement a transmission cost of service formula rate. PSO and SWEPCo requested an effective date of September 1, 2007 for the revised tariff. If approved as filed, the revised tariff will increase annual network transmission service revenues from nonaffiliated municipal and rural cooperative utilities in the AEP pricing zone of SPP by approximately $10 million. In August 2007, the FERC issued an order conditionally accepting PSO’s and SWEPCo’s proposed formula rate, subject to a compliance filing, suspended the effective date until February 1, 2008 and established a hearing schedule and settlement proceedings. New rates, subject to refund, were implemented in February 2008. Multiple intervenors have protested or requested re-hearing ofA settlement agreement was reached and has been filed with the order and settlement discussions are underway. Management believes it has recognized the appropriate amount of revenues, subject to refund, beginning in February 2008. If the final refund exceeds the provisions it would adversely affect future net income and cash flows. ManagementFERC. FERC approval is unable to predict the outcome of this proceeding.pending.
FERC Market Power MitigationTransmission Equalization Agreement – Affecting APCo, CSPCo, I&M and OPCo
The FERC allows utilities to sell wholesale power at market-based rates if they can demonstrate that they lack market powerCertain transmission equipment placed in the marketsservice in which they participate. Sellers with market rate authority must, at least every three years, update their studies demonstrating lack of market power. In December 2007, AEP filed its most recent triennial update. In March and May 2008, the PUCO filed comments suggesting that the FERC should further investigate whether AEP continues to pass the FERC’s indicative screens for the lack of market power in PJM. Certain industrial retail customers also requested the FERC to further investigate this matter. AEP responded that its market power studies were performed in accordance with the FERC’s guidelines and continue to demonstrate lack of market power. In September 2008, the FERC issued an order accepting AEP’s market-based rates with minor changes and rejected the PUCO’s and the industrial retail customers’ suggestions to further investigate AEP’s lack of market power.
In an unrelated matter, in May 2008, the FERC issued an order in response to a complaint1998 was inadvertently excluded from the state of Maryland’s Public Service CommissionAEP East companies’ TEA calculation prior to holdJanuary 2009. Management does not believe that it is probable that a future hearing to reviewmaterial retroactive rate adjustment will result from the structure of the three pivotal market power supplier tests in PJM. In September 2008, PJM filedomission. However, if a report on the results of the PJM stakeholder process concerning the three pivotal supplier market power tests which recommended the FERC not make major revisions to the test because the testretroactive adjustment is not unjust or unreasonable.
The FERC’s order will become final if no requestsrequired for rehearing are filed. If a request for rehearing is filed and ultimately results in a further investigation by the FERC which limits AEP’s ability to sell power at market-based rates in PJM, it would result in an adverse effect on future off-system sales margins and cash flows.
Allocation of Off-system Sales Margins – Affecting APCo, CSPCo, I&M and OPCo, PSO and SWEPCo
In 2004, intervenors and the OCC staff argued that AEP had inappropriately under-allocated off-system sales credits to PSO by $37 million for the period June 2000 to December 2004 under a FERC-approved allocation agreement. An ALJ assigned to hear intervenor claims found that the OCC lacked authority to examine whether AEP deviated from the FERC-approved allocation methodology for off-system sales margins and held that any such complaints should be addressed at the FERC. In October 2007, the OCC adopted the ALJ’s recommendation and orally directed the OCC staff to explore filing a complaint at the FERC alleging the allocation of off-system sales margins to PSO is not in compliance with the FERC-approved methodology which could result in an adverse effect on future net income and cash flows for AEP Consolidated, the AEP East companies and the AEP West companies. In June 2008, the ALJ issued a final recommendation and incorporated the prior finding that the OCC lacked authority to review AEP’s application of a FERC-approved methodology. In June 2008, the Oklahoma Industrial Energy Consumers appealed the ALJ recommendation to the OCC. In August 2008, the OCC heard the appeal and a decision is pending. See “PSO Fuel and Purchased Power” section within “Oklahoma Rate Matters”. In August 2008, the OCC filed a complaint at the FERC alleging that AEPSC inappropriately allocated off-system trading margins between the AEP East companies and the AEP West companies and did not properly allocate off-system trading margins within the AEP West companies. The PUCT, the APSC and the Oklahoma Industrial Energy Consumers have all intervened in this filing.
TCC, TNC and the PUCT have been involved in litigation in the federal courts concerning whether the PUCT has the right to order a reallocation of off-system sales margins thereby reducing recoverable fuel costs in the final fuel reconciliation in Texas under the restructuring legislation. In 2005, TCC and TNC recorded provisions for refunds after the PUCT ordered such reallocation. After receipt of favorable federal court decisions and the refusal of the U.S. Supreme Court to hear a PUCT appeal of the TNC decision, TCC and TNC reversed their provisions of $16 million and $9 million, respectively, in the third quarter of 2007.
Management cannot predict the outcome of these proceedings. However, management believes its allocations were in accordance with the then-existing FERC-approved allocation agreements and additional off-system sales margins should not be retroactively reallocated. The results of these proceedingsit could have an adverse effect on future net income, and cash flows for AEP Consolidated, the AEP East companies and the AEP West companies.financial condition.
4. | COMMITMENTS, GUARANTEES AND CONTINGENCIES |
4. COMMITMENTS, GUARANTEES AND CONTINGENCIES
The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation cannot be predicted. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material adverse effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 20072008 Annual Report should be read in conjunction with this report.
GUARANTEES
There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.
Letters of Credit – Affecting APCo, I&M, OPCo and SWEPCo
Certain Registrant Subsidiaries enter into standby letters of credit (LOCs) with third parties. These LOCs cover items such as insurance programs, security deposits and debt service reserves. These LOCs were issued in the Registrant Subsidiaries’ ordinary course of business under the two $1.5 billion credit facilities which were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $46 million following its bankruptcy.
In April 2008, theThe Registrant Subsidiaries and certain other companies in the AEP System entered intohave 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. As of September 30, 2008,March 31, 2009, $372 million of letters of credit were issued by Registrant Subsidiaries under the $650 million 3-year credit agreement to support variable rate demand notes.Pollution Control Bonds. In April 2009, the $350 million 364-day credit agreement expired.
At September 30, 2008,March 31, 2009, the maximum future payments of the LOCs were as follows:
| | | | | | Borrower |
Company | | Amount | | Maturity | | Sublimit |
| | (in thousands) | | | | | |
$1.5 billion LOC: | | | | | | | | |
I&M | | $ | 1,113 | | March 2009 | | | N/A |
SWEPCo | | | 4,000 | | December 2008 | | | N/A |
| | | | | | | | |
$650 million LOC: | | | | | | | | |
APCo | | $ | 126,717 | | June 2009 | | $ | 300,000 |
I&M | | | 77,886 | | May 2009 | | | 230,000 |
OPCo | | | 166,899 | | June 2009 | | | 400,000 |
| | | | | | Borrower |
| | Amount | | Maturity | | Sublimit |
Company | | (in thousands) | | | | | |
$1.5 billion LOC: | | | | | | | | |
I&M | | $ | 300 | | March 2010 | | | N/A |
SWEPCo | | | 4,448 | | December 2009 | | | N/A |
| | | | | | | | |
$650 million LOC: | | | | | | | | |
APCo | | $ | 126,716 | | June 2010 | | $ | 300,000 |
I&M | | | 77,886 | | May 2010 | | | 230,000 |
OPCo | | | 166,899 | | June 2010 | | | 400,000 |
Guarantees of Third-Party Obligations
– Affecting SWEPCo
As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation in the amount of approximately $65 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine Mining Company (Sabine), an entity consolidated under FIN 46R. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study, it is estimated the reserves will be depleted in 2029 with final reclamation completed by 2036, at an estimated cost of approximately $39 million. As of September 30, 2008,March 31, 2009, SWEPCo collected approximately $37$39 million through a rider for final mine closure costs, of which approximately $7$3 million is recorded in Other Current Liabilities, approximately $16 million is recorded in Asset Retirement Obligations and $30approximately $20 million is recorded in Deferred Credits and Other on SWEPCo’s Condensed Consolidated Balance Sheets.
Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause.
Indemnifications and Other Guarantees – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo
Contracts
All of theThe Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. Prior to September 30, 2008,March 31, 2009, Registrant Subsidiaries entered into sale agreements which included indemnifications with a maximum exposure that was not significant for any individual Registrant Subsidiary. There are no material liabilities recorded for any indemnifications.
The AEP East companies, PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to power purchase and sale activity conducted pursuant to the SIA.
Master Operating Lease Agreements
Certain Registrant Subsidiaries lease certain equipment under a master operating lease. Underlease agreements. GE Capital Commercial Inc. (GE) notified management in November 2008 that they elected to terminate the Master Leasing Agreements in accordance with the termination rights specified within the contract. In 2010 and 2011, the Registrant Subsidiaries will be required to purchase all equipment under the lease agreement,and pay GE an amount equal to the unamortized value of all equipment then leased. In December 2008, management signed new master lease agreements with one-year commitment periods that include lease terms of up to 10 years. Management expects to enter into additional replacement leasing arrangements for the equipment affected by this notification prior to the termination dates of 2010 and 2011.
For equipment under the GE master lease agreements that expire prior to 2011, the lessor is guaranteed to receivereceipt of up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, the Registrant Subsidiaries haveare committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. Historically,Under the new master lease agreements, the lessor is guaranteed receipt of up to 68% of the unamortized balance at the end of the lease term. If the actual fair market value of the leased equipment is below the unamortized balance at the end of the lease term, the Registrant Subsidiaries are committed to pay the difference between the actual fair market value has been in excessand unamortized balance, with the total guarantee not to exceed 68% of the unamortized balance. At September 30, 2008,March 31, 2009, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair market value of the equipment is zero at the end of the lease term is as follows:
| | Maximum | |
| | Potential | |
| | Loss | |
Company | | (in millions) | |
APCo | | | $ | 10 | |
CSPCo | | | | 5 | |
I&M | | | | 7 | |
OPCo | | | | 10 | |
PSO | | | | 6 | |
SWEPCo | | | | 6 | |
| Maximum | |
| Potential | |
| Loss | |
Company | (in thousands) | |
APCo | | $ | 1,055 | |
CSPCo | | | 431 | |
I&M | | | 720 | |
OPCo | | | 857 | |
PSO | | | 1,183 | |
SWEPCo | | | 799 | |
Railcar Lease
In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP intendsTransportation assigned the remaining 848 railcars under the original lease agreement to maintainI&M (390 railcars) and SWEPCo (458 railcars). The assignment is accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease forterm of twenty years, via the renewal options. The future minimum lease obligations are $20 million for I&M and $23 million for SWEPCo for the remaining railcars as of March 31, 2009.
Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines over the current lease term from approximately 84% under the current five-year lease term to 77% at the end of the 20-year term of the projected fair market value of the equipment.
In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignment is accounted for as new operating leases for I&M and SWEPCo. The future minimum lease obligation is $20 million for I&M and $23 million for SWEPCo as of September 30, 2008. I&M and SWEPCo intend to renew these leases for the full remaining terms and have assumed the guarantee under the return-and-sale option. I&M’s maximum potential loss related to the guarantee discussed above is approximately $12 million ($8 million, net of tax) and SWEPCo’s is approximately $14$13 million ($9 million, net of tax) assuming the fair market value of the equipment is zero at the end of the current five-year lease term.term. However, management believes that the fair market value would produce a sufficient sales price to avoid any loss.
The Registrant Subsidiaries have other railcar lease arrangements that do not utilize this type of financing structure.
CONTINGENCIES
Federal EPA Complaint and Notice of Violation – Affecting CSPCo
The Federal EPA, certain special interest groups and a number of states alleged that APCo, CSPCo, I&MDayton Power and OPCoLight Company and Duke Energy Ohio, Inc. modified certain units at their jointly-owned coal-fired generating plantsunits in violation of the NSR requirements of the CAA. The alleged modifications occurred over a 20-year period. Cases with similar allegations against CSPCo, Dayton Power and Light Company (DP&L) and Duke Energy Ohio, Inc. were also filed related to their jointly-owned units.
The AEP System settled their cases in 2007. In October 2008, the court approved a consent decree for a settlement reached with the Sierra Club in aA case involvingremains pending that could affect CSPCo’s share of jointly-owned units at the StuartBeckjord Station. The Stuart units, operated by DP&L, are equipped with SCR and flue gas desulfurization equipment (FGD or scrubbers) controls. Under the terms of the settlement, the joint-owners agreed to certain emission targets related to NOx, SO2 and PM. They also agreed to make energy efficiency and renewable energy commitments that are conditioned on receiving 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. AnotherBeckjord case involving a jointly-owned Beckjord unit had a liability trial in May 2008. Following the trial, the jury found no liability for claims made against the jointly-owned Beckjord unit. In December 2008, however, the court ordered a new trial in the Beckjord case. Beckjord is operated by Duke Energy Ohio, Inc.
Management is unable to estimate the loss or range of loss related to any contingent liability, if any, CSPCo might have for civil penalties under the pending CAA proceedings for Beckjord. Management is also unable to predict the timing of resolution of these matters. If CSPCo does not prevail, management believes CSPCo can recover any capital and operating costs of additional pollution control equipment that may be required through future regulated rates or market prices of electricity. If CSPCo is unable to recover such costs or if material penalties are imposed, it would adversely affect net income, cash flows and possibly financial condition.
Notice of Enforcement and Notice of Citizen Suit – Affecting SWEPCo
In March 2005, two special interest groups, Sierra Club and Public Citizen, filed a complaint in federal district courtFederal District Court for the Eastern District of Texas alleging violations of the CAA at SWEPCo’s Welsh Plant. In April 2008, the parties filed a proposed consent decree to resolve all claims in this case and in the pending appeal of the altered permit for the Welsh Plant. The consent decree requires SWEPCo to install continuous particulate emission monitors at the Welsh Plant, secure 65 MW of renewable energy capacity by 2010, fund $2 million in emission reduction, energy efficiency or environmental mitigation projects by 2012 and pay a portion of plaintiffs’ attorneys’ fees and costs. The consent decree was entered as a final order in June 2008.
In 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant. In April 2005, TCEQ issued an Executive Director’s Report (Report) recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of approximately $228 thousand against SWEPCo. In 2008, the matter was remanded to TCEQ to pursue settlement discussions. The original Report contained a recommendation to limit the heat input on each Welsh unit to the referenced heat input contained within the state permit within 10 days of the issuance of a final TCEQ order and until the permit is changed. SWEPCo had previously requested a permit alteration to remove the reference to a specific heat input value for each Welsh unit and to clarify the sulfur content requirement for fuels consumed at the plant. A permit alteration was issued in March 2007. In June 2007, TCEQ denied a motion to overturn the permit alteration. The permit alteration was appealed to the Travis County District Court, but was resolved by entry of the consent decree in the federal citizen suit action, and dismissed with prejudice in July 2008. Notice of an administrative settlement of the TCEQ enforcement action was published in June 2008. The settlement requires SWEPCo to pay an administrative penalty of $49 thousand and to fund a supplemental environmental project in the amount of $49 thousand, and resolves all violations alleged by TCEQ. In October 2008, TCEQ approved the settlement.
In February 2008, the Federal EPA issued a Notice of Violation (NOV) based on alleged violations of a percent sulfur in fuel limitation and the heat input values listed in the previous state permit. The NOV also alleges that the permit alteration issued by TCEQTexas Commission on Environmental Quality was improper. SWEPCo met with the Federal EPA to discuss the alleged violations in March 2008. The Federal EPA did not object to the settlement of similar alleged violations in the federal citizen suit.
Management is unable to predict the timing of any future action by the Federal EPA or the effect of such actionactions on net income, cash flows or financial condition.
Carbon Dioxide (CO2) Public Nuisance Claims – Affecting AEP East companiesCompanies and AEP West companiesCompanies
In 2004, eight states and the City of New York filed an action in federal district courtFederal District Court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority. The Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint against the same defendants. The actions allege that CO2 emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts of global warming, and sought injunctive relief in the form of specific emission reduction commitments from the defendants. The dismissal of this lawsuit was appealed to the Second Circuit Court of Appeals. Briefing and oral argument have concluded.concluded in 2006. In April 2007, the U.S. Supreme Court issued a decision holding that the Federal EPA has authority to regulate emissions of CO2 and other greenhouse gases under the CAA, which may impact the Second Circuit’s analysis of these issues. The Second Circuit requested supplemental briefs addressing the impact of the U.S. Supreme Court’s decision on this case.case which were provided in 2007. Management believes the actions are without merit and intends to defend against the claims.
Alaskan Villages’ Claims – Affecting AEP East companiesCompanies and AEP West companiesCompanies
In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in federal courtFederal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil & gas companies, a coal company and other electric generating companies. The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together. The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance. The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million. The defendants filed motions to dismiss the action. The motions are pending before the court. Management believes the action is without merit and intends to defend against the claims.
Clean Air Act Interstate Rule – Affecting Registrant Subsidiaries
In 2005, the Federal EPA issued a final rule, the Clean Air Interstate Rule (CAIR), that required 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). 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 issued a decision that would vacate the CAIR and remand the rule to the Federal EPA. In September 2008, the Federal EPA and other parties petitioned for rehearing. Management is 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.
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 as of September 30, 2008. The market value of annual CAIR NOx allowances decreased following this court decision. However, the 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 the other Registrant Subsidiaries purchased any significant number of CAIR allowances. SO2 and seasonal NOx allowances allocated to the Registrant Subsidiaries’ 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 environmental compliance strategy. However, independent obligations under the CAA, including obligations under future state implementation plan submittals, and actions taken pursuant to the settlement of the NSR enforcement action, are consistent with the actions included in a least-cost CAIR compliance plan. Consequently, management does not anticipate making any immediate changes in near-term compliance plans as a result of these court decisions.
The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation – Affecting I&M |
By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls (PCBs) and other hazardous and nonhazardous materials. The Registrant SubsidiariesCosts are currently incur costsbeing incurred to safely dispose of these substances.
Superfund addresses clean-up of hazardous substances that have been released to the environment. The Federal EPA administers the clean-up programs. Several states have enacted similar laws. In March 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M requested remediation proposals from environmental consulting firms. In May 2008, I&M issued a contract to one of the consulting firms.firms and started remediation work in accordance with a plan approved by MDEQ. I&M recorded approximately $4 million of expense through September 30,during 2008. Based upon updated information, I&M recorded additional expense of $3 million in March 2009. As the remediation work is completed, I&M’s cost may continue to increase. I&M cannot predict the amount of additional cost, if any. At present, management’s estimates do
Defective Environmental Equipment – Affecting CSPCo and OPCo
As part of the AEP System’s continuing environmental investment program, management chose to retrofit wet flue gas desulfurization systems on units utilizing the JBR technology. The retrofits on two units are operational. Due to unexpected operating results, management completed an extensive review of the design and manufacture of the JBR internal components. The review concluded that there are fundamental design deficiencies and that inferior and/or inappropriate materials were selected for the internal fiberglass components. Management initiated discussions with Black & Veatch, the original equipment manufacturer, to develop a repair or replacement corrective action plan. Management intends to pursue contractual and other legal remedies if these issues with Black & Veatch are not anticipate material cleanupresolved. If the AEP System is unsuccessful in obtaining reimbursement for the work required to remedy this situation, the cost of repair or replacement could have an adverse impact on construction costs, for this site.net income, cash flows or financial condition.
Cook Plant Unit 1 Fire and Shutdown – Affecting I&M
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 Cook Plant Unit 1 (Unit 1) due to turbine vibrations, likely caused by blade failure, which resulted in a fire on the electric generator. This equipment, islocated in the turbine building, and is separate and isolated from the nuclear reactor. The steam turbinesturbine rotors that caused the vibration were installed in 2006 and are underwithin the vendor’s warranty from the vendor.period. The warranty provides for the repair or replacement of the turbinesturbine rotors if the damage was caused by a defect in the designmaterials or assembly of the turbines.workmanship. I&M is also working with its insurance company, Nuclear Electric Insurance Limited (NEIL), and its turbine vendor, Siemens, to evaluate the extent of the damage resulting from the incident and the costsfacilitate repairs to return the unit to service. Management cannot estimate the ultimate costsRepair of the outage at this time.property damage and replacement of the turbine rotors and other equipment could cost up to approximately $330 million. Management believes that I&M should recover a significant portion of these costs through the turbine vendor’s warranty, insurance and the regulatory process. Management's preliminary analysis indicates thatThe treatment of property damage costs, replacement power costs and insurance proceeds will be the subject of future regulatory proceedings in Indiana and Michigan. I&M is repairing Unit 1 couldto resume operations as early as late first quarter/early second quarterOctober 2009 at reduced power. Should post-repair operations prove unsuccessful, the replacement of parts will extend the outage into 2011.
The refueling outage scheduled for the fall of 2009 or as late asfor Unit 1 was rescheduled to the second halfspring of 2009, depending upon whether2010. Management anticipates that the damaged components can be repaired or whether they needloss of capacity from Unit 1 will not affect I&M’s ability to be replaced.serve customers due to the existence of sufficient generating capacity in the AEP Power Pool.
I&M maintains property insurance through NEIL with a $1 million deductible. As of March 31, 2009, I&M recorded $34 million in Prepayments and Other on the Condensed Consolidated Balance Sheets representing recoverable amounts under the property insurance policy. I&M received partial reimbursement from NEIL for the cost incurred to date to repair the property damage. I&M also maintains a separate accidental outage policy with NEIL whereby, after a 12 week12-week deductible period, I&M is entitled to weekly payments of $3.5 million duringfor the first 52 weeks following the deductible period. After the initial 52 weeks of indemnity, the policy pays $2.8 million per week for up to an additional 110 weeks. I&M began receiving payments under the accidental outage period for a covered loss.policy in December 2008. In the first quarter of 2009, I&M recorded $54 million in revenues, including $9 million that were deferred at December 31, 2008, related to the accidental outage policy. In order to hold customers harmless, in the first quarter of 2009, I&M applied $20 million of the accidental outage insurance proceeds to reduce fuel underrecoveries reflecting recoverable fuel costs as if Unit 1 were operating. 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.
Coal Transportation Rate Dispute - Affecting PSO
In 1985, the Burlington Northern Railroad Co. (now BNSF) entered into a coal transportation agreement with PSO. The agreement contained a base rate subject to adjustment, a rate floor, a reopener provision and an arbitration provision. In 1992, PSO reopened the pricing provision. The parties failed to reach an agreement and the matter was arbitrated, with the arbitration panel establishing a lowered rate as of July 1, 1992 (the 1992 Rate), and modifying the rate adjustment formula. The decision did not mention the rate floor. From April 1996 through the contract termination in December 2001, the 1992 Rate exceeded the adjusted rate, determined according to the decision. PSO paid the adjusted rate and contended that the panel eliminated the rate floor. BNSF invoiced at the 1992 Rate and contended that the 1992 Rate was the new rate floor. At the end of 1991, PSO terminated the contract by paying a termination fee, as required by the agreement. BNSF contends that the termination fee should have been calculated on the 1992 Rate, not the adjusted rate, resulting in an underpayment of approximately $9.5 million, including interest.
This matter was submitted to an arbitration board. In April 2006, the arbitration board filed its decision, denying BNSF’s underpayments claim. PSO filed a request for an order confirming the arbitration award and a request for entry of judgment on the award with the U.S. District Court for the Northern District of Oklahoma. On July 14, 2006, the U.S. District Court issued an order confirming the arbitration award. On July 24, 2006, BNSF filed a Motion to Reconsider the July 14, 2006 Arbitration Confirmation Order and Final Judgment and its Motion to Vacate and Correct the Arbitration Award with the U.S. District Court. In February 2007, the U.S. District Court granted BNSF’s Motion to Reconsider. PSO filed a substantive response to BNSF’s motion and BNSF filed a reply. Management continues to defend its position that PSO paid BNSF all amounts owed.
Rail Transportation Litigation – Affecting PSO
In October 2008, the Oklahoma Municipal Power Authority and the Public Utilities Board of the City of Brownsville, Texas, as co-owners of Oklaunion Plant, filed a lawsuit in United States District Court, Western District of Oklahoma against AEP alleging breach of contract and breach of fiduciary duties related to negotiations for rail transportation services for the plant. The plaintiffs allege that AEP tookassumed the dutyduties of the project manager, PSO, and operated the plant for the project manager and is therefore responsible for the alleged breaches. In December 2008, the court denied AEP’s motion to dismiss the case. Management intends to vigorously defend against these allegations. Management believes a provision recorded in 2008 should be sufficient.
FERC Long-term Contracts – Affecting AEP East companiesCompanies and AEP West companiesCompanies
In 2002, the FERC held a hearing related to a complaint filed by Nevada Power Company and Sierra Pacific Power Company (the Nevada utilities). The complaint sought to break long-term contracts entered during the 2000 and 2001 California energy price spike which the customers alleged were “high-priced.” The complaint alleged that AEP subsidiaries sold power at unjust and unreasonable prices because the market for power was allegedly dysfunctional at the time such contracts were executed. In 2003, the FERC rejected the complaint. In 2006, the U.S. Court of Appeals for the Ninth Circuit reversed the FERC order and remanded the case to the FERC for further proceedings. That decision was appealed to the U.S. Supreme Court. In June 2008, the U.S. Supreme Court affirmed the validity of contractually-agreed rates except in cases of serious harm to the public. The U.S. Supreme Court affirmed the Ninth Circuit’s remand on two issues, market manipulation and excessive burden on consumers. The FERC initiated remand procedures and gave the parties time to attempt to settle the issues. Management is unable to predict the outcome of these proceedings or their impact on future net income and cash flows.believes a provision recorded in 2008 should be sufficient. The Registrant Subsidiaries asserted claims against certain companies that sold power to them, which was resold to the Nevada utilities, seeking to recover a portion of any amounts the Registrant Subsidiaries may owe to the Nevada utilities.
2008
None
2007
Darby Electric Generating Station – Affecting CSPCo
In November 2006, CSPCo agreed Management is unable to purchase Darby Electric Generating Station (Darby) from DPL Energy, LLC, a subsidiarypredict the outcome of The Dayton Powerthese proceedings or their ultimate impact on future net income and Light Company, for $102 million and the assumption of liabilities of $2 million. CSPCo completed the purchase in April 2007. The Darby plant is located near Mount Sterling, Ohio and is a natural gas, simple cycle power plant with a generating capacity of 480 MW.cash flows.
APCo, CSPCo, I&M, OPCo, PSO and SWEPCo participate in AEP sponsored qualified pension plans and nonqualified pension plans. A substantial majority of employees are covered by either one qualified plan or both a qualified and a nonqualified pension plan. In addition, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo participate in other postretirement benefit plans sponsored by AEP to provide medical and death benefits for retired employees.
Components of Net Periodic Benefit Cost
The following tables providetable provides the components of AEP’s net periodic benefit cost for the plans for the three and nine months ended September 30, 2008March 31, 2009 and 2007:2008:
| | | Other Postretirement | |
| Pension Plans | | Benefit Plans | |
| Three Months Ended September 30, | | Three Months Ended September 30, | |
| 2008 | | 2007 | | 2008 | | 2007 | |
| (in millions) | |
Service Cost | | $ | 25 | | | $ | 24 | | | $ | 10 | | | $ | 11 | |
Interest Cost | | | 62 | | | | 59 | | | | 28 | | | | 26 | |
Expected Return on Plan Assets | | | (84 | ) | | | (85 | ) | | | (27 | ) | | | (26 | ) |
Amortization of Transition Obligation | | | - | | | | - | | | | 7 | | | | 6 | |
Amortization of Net Actuarial Loss | | | 10 | | | | 15 | | | | 3 | | | | 3 | |
Net Periodic Benefit Cost | | $ | 13 | | | $ | 13 | | | $ | 21 | | | $ | 20 | |
| | | Other Postretirement | |
| Pension Plans | | Benefit Plans | |
| Three Months Ended March 31, | | Three Months Ended March 31, | |
| 2009 | | 2008 | | 2009 | | 2008 | |
| (in millions) | |
Service Cost | | $ | 26 | | | $ | 25 | | | $ | 10 | | | $ | 10 | |
Interest Cost | | | 63 | | | | 63 | | | | 27 | | | | 28 | |
Expected Return on Plan Assets | | | (80 | ) | | | (84 | ) | | | (20 | ) | | | (28 | ) |
Amortization of Transition Obligation | | | - | | | | - | | | | 7 | | | | 7 | |
Amortization of Net Actuarial Loss | | | 15 | | | | 9 | | | | 11 | | | | 3 | |
Net Periodic Benefit Cost | | $ | 24 | | | $ | 13 | | | $ | 35 | | | $ | 20 | |
| | | Other Postretirement | |
| Pension Plans | | Benefit Plans | |
| Nine Months Ended September 30, | | Nine Months Ended September 30, | |
| 2008 | | 2007 | | 2008 | | 2007 | |
| (in millions) | |
Service Cost | | $ | 75 | | | $ | 72 | | | $ | 31 | | | $ | 32 | |
Interest Cost | | | 187 | | | | 176 | | | | 84 | | | | 78 | |
Expected Return on Plan Assets | | | (252 | ) | | | (254 | ) | | | (83 | ) | | | (78 | ) |
Amortization of Transition Obligation | | | - | | | | - | | | | 21 | | | | 20 | |
Amortization of Net Actuarial Loss | | | 29 | | | | 44 | | | | 8 | | | | 9 | |
Net Periodic Benefit Cost | | $ | 39 | | | $ | 38 | | | $ | 61 | | | $ | 61 | |
The following tables providetable provides the Registrant Subsidiaries’ net periodic benefit cost (credit) for the plans for the three and nine months ended September 30, 2008March 31, 2009 and 2007:2008:
| | | Other Postretirement | |
| Pension Plans | | Benefit Plans | |
| Three Months Ended September 30, | | Three Months Ended September 30, | |
| 2008 | | 2007 | | 2008 | | 2007 | |
Company | (in thousands) | |
APCo | | $ | 834 | | | $ | 841 | | | $ | 3,797 | | | $ | 3,560 | |
CSPCo | | | (351 | ) | | | (258 | ) | | | 1,545 | | | | 1,491 | |
I&M | | | 1,821 | | | | 1,900 | | | | 2,496 | | | | 2,530 | |
OPCo | | | 318 | | | | 362 | | | | 2,908 | | | | 2,802 | |
PSO | | | 509 | | | | 425 | | | | 1,420 | | | | 1,431 | |
SWEPCo | | | 935 | | | | 747 | | | | 1,411 | | | | 1,420 | |
| | | Other Postretirement | | | | Other Postretirement | |
| Pension Plans | | Benefit Plans | | Pension Plans | | Benefit Plans | |
| Nine Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended March 31, | | Three Months Ended March 31, | |
| 2008 | | 2007 | | 2008 | | 2007 | | 2009 | | 2008 | | 2009 | | 2008 | |
Company | (in thousands) | | (in thousands) | |
APCo | | $ | 2,503 | | | $ | 2,525 | | | $ | 11,196 | | | $ | 10,680 | | | $ | 2,615 | | | $ | 835 | | | $ | 6,058 | | | $ | 3,699 | |
CSPCo | | | (1,049 | ) | | | (773 | ) | | | 4,542 | | | | 4,473 | | | | 688 | | | | (349 | ) | | | 2,638 | | | | 1,498 | |
I&M | | | 5,462 | | | | 5,700 | | | | 7,342 | | | | 7,591 | | | | 3,485 | | | | 1,821 | | | | 4,358 | | | | 2,423 | |
OPCo | | | 957 | | | | 1,088 | | | | 8,541 | | | | 8,405 | | | | 2,067 | | | | 319 | | | | 5,139 | | | | 2,816 | |
PSO | | | 1,525 | | | | 1,273 | | | | 4,194 | | | | 4,292 | | | | 770 | | | | 508 | | | | 2,283 | | | | 1,387 | |
SWEPCo | | | 2,806 | | | | 2,240 | | | | 4,163 | | | | 4,258 | | | | 1,208 | | | | 935 | | | | 2,363 | | | | 1,376 | |
AEP hassponsors several trust funds with significant investments in several trust fundsintended to provide for future pension and OPEB payments. All of the 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 from the December 31, 2008 balances due to the decreases in the equity and fixed income markets. Although the asset values are currently lower than at year end, this decline has not affected the funds’ ability to make their required payments.
The Registrant Subsidiaries have one reportable segment. The one reportable segment is an electricity generation, transmission and distribution business. All of the Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed as one segment because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
8.7. | INCOME TAXESDERIVATIVES, HEDGING AND FAIR VALUE MEASUREMENTS |
DERIVATIVES AND HEDGING
Objectives for Utilization of Derivative Instruments
The Registrant Subsidiaries adopted FIN 48are exposed to certain market risks as major power producers and marketers of January 1, 2007. Aswholesale electricity, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and to a result,lesser extent foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries recognized an increasedue to changes in the underlying market prices or rates. These risks are managed using derivative instruments.
Strategies for Utilization of Derivative Instruments to Achieve Objectives
The Registrant Subsidiaries’ strategy surrounding the use of derivative instruments focuses on managing risk exposures, future cash flows and creating value based on open trading positions by utilizing both economic and formal SFAS 133 hedging strategies. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical forward purchase and sale contracts, financial forward purchase and sale contracts and financial swap instruments. Not all risk management contracts meet the definition of a derivative under SFAS 133. Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of SFAS 133.
AEPSC, on behalf of the Registrant Subsidiaries, enters into electricity, coal, natural gas, interest rate and to a lesser degree heating oil, gasoline, emission allowance and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with long-term commodity derivative positions. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. From time to time, AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors.
The following table represents the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of March 31, 2009:
Notional Volume of Derivative Instruments | |
March 31, 2009 | |
(in thousands) | |
| |
Primary Risk Exposure | | Unit of Measure | | APCo | | | CSPCo | | | I&M | | | OPCo | | | PSO | | | SWEPCo | |
Commodity: | | | | | |
Power | | MWHs | | | 102,761 | | | | 54,500 | | | | 52,744 | | | | 67,512 | | | | 609 | | | | 718 | |
Coal | | Tons | | | 10,972 | | | | 5,551 | | | | 5,860 | | | | 18,810 | | | | 3,012 | | | | 4,853 | |
Natural Gas | | MMBtus | | | 37,953 | | | | 20,129 | | | | 19,480 | | | | 24,935 | | | | 4,887 | | | | 5,760 | |
Heating Oil and Gasoline | | Gallons | | | 871 | | | | 360 | | | | 415 | | | | 627 | | | | 494 | | | | 466 | |
Interest Rate | | USD | | $ | 41,480 | | | $ | 21,959 | | | $ | 21,325 | | | $ | 28,946 | | | $ | 2,552 | | | $ | 3,207 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Interest Rate and Foreign Currency | | USD | | $ | - | | | $ | - | | | $ | - | | | $ | 400,000 | | | $ | - | | | $ | 3,918 | |
Fair Value Hedging Strategies
At certain times, AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative transactions in order to manage an existing fixed interest rate risk exposure. These interest rate derivative transactions effectively modify an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. This strategy is not actively employed by any of the Registrant Subsidiaries in 2009. During 2008, APCo had designated interest rate derivatives as fair value hedges.
Cash Flow Hedging Strategies
AEPSC, on behalf of the Registrant Subsidiaries, enters into and designate as cash flow hedges certain derivative transactions for the purchase and sale of electricity, coal and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. Management closely monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk. During 2009 and 2008, APCo, CSPCo, I&M and OPCo designated cash flow hedging relationships using these commodities.
The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial gasoline and heating oil derivative contracts in order mitigate price risk of future fuel purchases. The Registrant Subsidiaries do not hedge all fuel price risk. During 2009, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo designated cash flow hedging strategies of forecasted fuel purchases. This strategy was not active for any of the Registrant Subsidiaries during 2008. For disclosure purposes, these contracts are included with other hedging activity as “Commodity.”
AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to anticipated borrowings of fixed-rate debt. The anticipated fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure. During 2009 and 2008, APCo and OPCo designated interest rate derivatives as cash flow hedges.
At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily because some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency exposure. During 2009 and 2008, APCo, OPCo and SWEPCo designated foreign currency derivatives as cash flow hedges.
Accounting for Derivative Instruments and the Impact on the Financial Statements
SFAS 133 requires recognition of all qualifying derivative instruments as either assets or liabilities in the balance sheet at fair value. The fair values of derivative instruments accounted for unrecognized tax benefits,using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrant Subsidiaries also apply valuation adjustments for discounting, liquidity and credit quality.
Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.
According to FSP FIN 39-1, the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the March 31, 2009 and December 31, 2008 balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows:
| March 31, 2009 | | December 31, 2008 | |
| Cash Collateral | | Cash Collateral | | Cash Collateral | | Cash Collateral | |
| Received | | Paid | | Received | | Paid | |
| Netted Against | | Netted Against | | Netted Against | | Netted Against | |
| Risk Management | | Risk Management | | Risk Management | | Risk Management | |
| Assets | | Liabilities | | Assets | | Liabilities | |
Company | (in thousands) | |
APCo | | $ | 25,038 | | | $ | 36,012 | | | $ | 2,189 | | | $ | 5,621 | |
CSPCo | | | 13,279 | | | | 19,092 | | | | 1,229 | | | | 3,156 | |
I&M | | | 12,851 | | | | 18,481 | | | | 1,189 | | | | 3,054 | |
OPCo | | | 16,450 | | | | 23,662 | | | | 1,522 | | | | 3,909 | |
PSO | | | - | | | | 393 | | | | - | | | | 105 | |
SWEPCo | | | - | | | | 456 | | | | - | | | | 124 | |
The following table represents the gross fair value impact of the Registrant Subsidiaries’ derivative activity on the Condensed Balance Sheets as of March 31, 2009:
Fair Value of Derivative Instruments | |
March 31, 2009 | |
| |
APCo | Risk Management Contracts | | Hedging Contracts | | | | | |
| Commodity (a) | | Commodity (a) | | Interest Rate and Foreign Currency | | Other (b) | | Total | |
Balance Sheet Location | (in thousands) | |
Current Risk Management Assets | | $ | 672,985 | | | $ | 8,048 | | | $ | - | | | $ | (605,838 | ) | | $ | 75,195 | |
Long-Term Risk Management Assets | | | 276,740 | | | | 615 | | | | - | | | | (212,584 | ) | | | 64,771 | |
Total Assets | | | 949,725 | | | | 8,663 | | | | - | | | | (818,422 | ) | | | 139,966 | |
| | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | | | 645,041 | | | | 1,996 | | | | - | | | | (607,945 | ) | | | 39,092 | |
Long-Term Risk Management Liabilities | | | 258,749 | | | | 419 | | | | - | | | | (229,113 | ) | | | 30,055 | |
Total Liabilities | | | 903,790 | | | | 2,415 | | | | - | | | | (837,058 | ) | | | 69,147 | |
| | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 45,935 | | | $ | 6,248 | | | $ | - | | | $ | 18,636 | | | $ | 70,819 | |
CSPCo | | | | | | | | | | | | | | | |
| | Risk Management Contracts | | | Hedging Contracts | | | | | | | |
| | Commodity (a) | | | Commodity (a) | | | Interest Rate and Foreign Currency | | | Other (b) | | | Total | |
Balance Sheet Location | | (in thousands) | |
Current Risk Management Assets | | $ | 354,953 | | | $ | 4,268 | | | $ | - | | | $ | (319,634 | ) | | $ | 39,587 | |
Long-Term Risk Management Assets | | | 146,110 | | | | 326 | | | | - | | | | (112,128 | ) | | | 34,308 | |
Total Assets | | | 501,063 | | | | 4,594 | | | | - | | | | (431,762 | ) | | | 73,895 | |
| | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | | | 340,254 | | | | 1,050 | | | | - | | | | (320,743 | ) | | | 20,561 | |
Long-Term Risk Management Liabilities | | | 136,595 | | | | 222 | | | | - | | | | (120,894 | ) | | | 15,923 | |
Total Liabilities | | | 476,849 | | | | 1,272 | | | | - | | | | (441,637 | ) | | | 36,484 | |
| | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 24,214 | | | $ | 3,322 | | | $ | - | | | $ | 9,875 | | | $ | 37,411 | |
I&M | | | | | | | | | | | | | | | |
| | Risk Management Contracts | | | Hedging Contracts | | | | | | | |
| | Commodity (a) | | | Commodity (a) | | | Interest Rate and Foreign Currency | | | Other (b) | | | Total | |
Balance Sheet Location | | (in thousands) | |
Current Risk Management Assets | | $ | 347,018 | | | $ | 4,131 | | | $ | - | | | $ | (312,391 | ) | | $ | 38,758 | |
Long-Term Risk Management Assets | | | 142,607 | | | | 315 | | | | - | | | | (109,640 | ) | | | 33,282 | |
Total Assets | | | 489,625 | | | | 4,446 | | | | - | | | | (422,031 | ) | | | 72,040 | |
| | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | | | 332,550 | | | | 1,021 | | | | - | | | | (313,470 | ) | | | 20,101 | |
Long-Term Risk Management Liabilities | | | 133,350 | | | | 214 | | | | - | | | | (118,124 | ) | | | 15,440 | |
Total Liabilities | | | 465,900 | | | | 1,235 | | | | - | | | | (431,594 | ) | | | 35,541 | |
| | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 23,725 | | | $ | 3,211 | | | $ | - | | | $ | 9,563 | | | $ | 36,499 | |
OPCo | | | | | | | | | | | | | | | |
| | Risk Management Contracts | | | Hedging Contracts | | | | | | | |
| | Commodity (a) | | | Commodity (a) | | | Interest Rate and Foreign Currency | | | Other (b) | | | Total | |
Balance Sheet Location | | (in thousands) | |
Current Risk Management Assets | | $ | 525,935 | | | $ | 5,288 | | | $ | 1,329 | | | $ | (469,192 | ) | | $ | 63,360 | |
Long-Term Risk Management Assets | | | 210,595 | | | | 404 | | | | - | | | | (165,334 | ) | | | 45,665 | |
Total Assets | | | 736,530 | | | | 5,692 | | | | 1,329 | | | | (634,526 | ) | | | 109,025 | |
| | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | | | 504,236 | | | | 1,314 | | | | 925 | | | | (470,580 | ) | | | 35,895 | |
Long-Term Risk Management Liabilities | | | 200,912 | | | | 275 | | | | - | | | | (176,192 | ) | | | 24,995 | |
Total Liabilities | | | 705,148 | | | | 1,589 | | | | 925 | | | | (646,772 | ) | | | 60,890 | |
| | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 31,382 | | | $ | 4,103 | | | $ | 404 | | | $ | 12,246 | | | $ | 48,135 | |
| | | | | | | | | | | | | | | | | | | | |
PSO | | | | | | | | | | | | | | | |
| | Risk Management Contracts | | | Hedging Contracts | | | | | | | |
| | Commodity (a) | | | Commodity (a) | | | Interest Rate and Foreign Currency | | | Other (b) | | | Total | |
Balance Sheet Location | | (in thousands) | |
Current Risk Management Assets | | $ | 41,231 | | | $ | - | | | $ | - | | | $ | (33,599 | ) | | $ | 7,632 | |
Long-Term Risk Management Assets | | | 7,811 | | | | - | | | | - | | | | (7,211 | ) | | | 600 | |
Total Assets | | | 49,042 | | | | - | | | | - | | | | (40,810 | ) | | | 8,232 | |
| | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | | | 39,566 | | | | 33 | | | | - | | | | (33,892 | ) | | | 5,707 | |
Long-Term Risk Management Liabilities | | | 7,523 | | | | - | | | | - | | | | (7,143 | ) | | | 380 | |
Total Liabilities | | | 47,089 | | | | 33 | | | | - | | | | (41,035 | ) | | | 6,087 | |
| | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 1,953 | | | $ | (33 | ) | | $ | - | | | $ | 225 | | | $ | 2,145 | |
SWEPCo | | | | | | | | | | | | | | | |
| | Risk Management Contracts | | | Hedging Contracts | | | | | | | |
| | Commodity (a) | | | Commodity (a) | | | Interest Rate and Foreign Currency | | | Other (b) | | | Total | |
Balance Sheet Location | | (in thousands) | |
Current Risk Management Assets | | $ | 57,959 | | | $ | - | | | $ | - | | | $ | (47,772 | ) | | $ | 10,187 | |
Long-Term Risk Management Assets | | | 12,427 | | | | - | | | | 1 | | | | (11,508 | ) | | | 920 | |
Total Assets | | | 70,386 | | | | - | | | | 1 | | | | (59,280 | ) | | | 11,107 | |
| | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | | | 55,344 | | | | 30 | | | | 301 | | | | (48,110 | ) | | | 7,565 | |
Long-Term Risk Management Liabilities | | | 11,956 | | | | - | | | | - | | | | (11,428 | ) | | | 528 | |
Total Liabilities | | | 67,300 | | | | 30 | | | | 301 | | | | (59,538 | ) | | | 8,093 | |
| | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | $ | 3,086 | | | $ | (30 | ) | | $ | (300 | ) | | $ | 258 | | | $ | 3,014 | |
(a) | Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented in the Condensed Balance Sheets on a net basis in accordance with FIN 39 “Offsetting of Amounts Related to Certain Contracts.” |
(b) | Amounts represent counterparty netting of risk management contracts, associated cash collateral in accordance with FSP FIN 39-1 and dedesignated risk management contracts. |
The table below presents the Registrant Subsidiaries MTM activity of derivative risk management contracts for the three months ended March 31, 2009:
Amount of Gain (Loss) Recognized on Risk Management Contracts | |
For the Three Months Ended March 31, 2009 | |
| | | | | | | | | | | | |
| APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo | |
| (in thousands) | |
Location of Gain (Loss) | | | | | | | | | | | | | | | | | | |
Electric Generation, Transmission and Distribution Revenues | | $ | 9,817 | | | $ | 10,745 | | | $ | 18,178 | | | $ | 12,711 | | | $ | 1,255 | | | $ | 1,523 | |
Sales to AEP Affiliates | | | (7,020 | ) | | | (4,076 | ) | | | (3,971 | ) | | | (3,214 | ) | | | (1,462 | ) | | | (1,781 | ) |
Regulatory Assets | | | (755 | ) | | | - | | | | - | | | | - | | | | - | | | | (41 | ) |
Regulatory Liabilities | | | 38,861 | | | | 11,628 | | | | 6,940 | | | | 13,856 | | | | 334 | | | | 386 | |
Total Gain (Loss) on Risk Management Contracts | | $ | 40,903 | | | $ | 18,297 | | | $ | 21,147 | | | $ | 23,353 | | | $ | 127 | | | $ | 87 | |
Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in SFAS 133. Derivative contracts that have been designated as normal purchases or normal sales under SFAS 133 are not subject to MTM accounting treatment and are recognized in the Condensed Statements of Income on an accrual basis.
The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.
For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in Revenues on a net basis in the Condensed Statements of Income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in Revenues or Expenses on the Condensed Statements of Income depending on the relevant facts and circumstances. However, unrealized and realized gains and losses in regulated jurisdictions (APCo, I&M, PSO and the non-Texas portion of SWEPCo) for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with SFAS 71.
Accounting for Fair Value Hedging Strategies
For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the Registrant Subsidiaries recognize the gain or loss on the derivative instrument as well as related interest expense and penalties, which was accounted for as a reduction to the January 1, 2007 balanceoffsetting gain or loss on the hedged item associated with the hedged risk in Net Income during the period of retained earnings by each Registrant Subsidiary.change.
The Registrant Subsidiaries joinrecord realized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the filingfair value of the debt being hedged, in Interest Expense on the Condensed Statements of Income. During the three months ended March 31, 2009, the Registrant Subsidiaries did not employ any fair value hedging strategies. During the three months ended 2008, APCo designated interest rate derivatives as fair value hedges and did not recognize any hedge ineffectiveness related to these derivative transactions.
Accounting for Cash Flow Hedging Strategies
For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).
Realized gains and losses on derivatives transactions for the purchase and sale of electricity, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale in the Condensed Statements of Income, depending on the specific nature of the risk being hedged. The Registrant Subsidiaries do not hedge all variable price risk exposure related to commodities. During the three months ended March 31, 2009 and 2008, APCo, CSPCo, I&M and OPCo recognized immaterial amounts in Net Income related to hedge ineffectiveness.
Beginning in 2009, the Registrant Subsidiaries executed financial heating oil and gasoline derivative contracts to hedge the price risk of diesel fuel and gasoline purchases. The Registrant Subsidiaries reclassify gains and losses on financial fuel derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets into Other Operation and Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the Condensed Statements of Income. The Registrant Subsidiaries do not hedge all fuel price exposure. During the three months ended March 31, 2009, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo recognized no hedge ineffectiveness related to this hedge strategy.
The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financing from Accumulated Other Comprehensive Income (Loss) into Interest Expense in those periods in which hedged interest payments occur. During the three months ended March 31, 2009 and 2008, APCo and OPCo recognized immaterial amounts in Net Income related to hedge ineffectiveness.
The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets into Depreciation and Amortization expense in the Condensed Statements of Income over the depreciable lives of the fixed assets that were designated as the hedged items in qualifying foreign currency hedging relationships. The Registrant Subsidiaries do not hedge all foreign currency exposure. During the three months ended March 31, 2009 and 2008, APCo, OPCo and SWEPCo recognized no hedge ineffectiveness related to this hedge strategy.
The following table provides details on designated, effective cash flow hedges included in AOCI on the Condensed Balance Sheets and the reasons for changes in cash flow hedges from January 1, 2009 to March 31, 2009. All amounts in the following table are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | |
For the Three Months Ended March 31, 2009 | |
| | | | | | | | | | | | |
| APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo | |
| (in thousands) | |
Commodity Contracts | | | | | | | | | | | | | | | | | | |
Beginning Balance in AOCI as of January 1, 2009 | | $ | 2,726 | | | $ | 1,531 | | | $ | 1,482 | | | $ | 1,898 | | | $ | - | | | $ | - | |
Changes in Fair Value Recognized in AOCI | | | 380 | | | | 118 | | | | 113 | | | | 136 | | | | (24 | ) | | | (21 | ) |
Amount of (Gain) or Loss Reclassified from AOCI to Income Statements/within Balance Sheets: | | | | | | | | | | | | | | | | | | | | | | | | |
Electric Generation, Transmission and Distribution Revenues | | | (251 | ) | | | (613 | ) | | | (504 | ) | | | (759 | ) | | | - | | | | - | |
Purchased Electricity for Resale | | | 462 | | | | 1,126 | | | | 926 | | | | 1,394 | | | | - | | | | - | |
Regulatory Assets | | | 1,639 | | | | - | | | | 163 | | | | - | | | | - | | | | - | |
Regulatory Liabilities | | | (890 | ) | | | - | | | | (89 | ) | | | - | | | | - | | | | - | |
Ending Balance in AOCI as of March 31, 2009 | | $ | 4,066 | | | $ | 2,162 | | | $ | 2,091 | | | $ | 2,669 | | | $ | (24 | ) | | $ | (21 | ) |
| | | | | | | | | | | | | | | | | | |
| | APCo | | | CSPCo | | | I&M | | | OPCo | | | PSO | | | SWEPCo | |
| | (in thousands) | |
Interest Rate and Foreign Currency Contracts | | | | | | | | | | | | | | | | | | |
Beginning Balance in AOCI as of January 1, 2009 | | $ | (8,118 | ) | | $ | - | | | $ | (10,521 | ) | | $ | 1,752 | | | $ | (704 | ) | | $ | (5,924 | ) |
Changes in Fair Value Recognized in AOCI | | | - | | | | - | | | | - | | | | 263 | | | | - | | | | (91 | ) |
Amount of (Gain) or Loss Reclassified from AOCI to Income Statements/within Balance Sheets: | | | | | | | | | | | | | | | | | | | | | | | | |
Depreciation and Amortization Expense | | | - | | | | - | | | | (2 | ) | | | 1 | | | | - | | | | - | |
Interest Expense | | | 416 | | | | - | | | | 252 | | | | 23 | | | | 46 | | | | 207 | |
Ending Balance in AOCI as of March 31, 2009 | | $ | (7,702 | ) | | $ | - | | | $ | (10,271 | ) | | $ | 2,039 | | | $ | (658 | ) | | $ | (5,808 | ) |
| | | | | | | | | | | | | | | | | | |
| | APCo | | | CSPCo | | | I&M | | | OPCo | | | PSO | | | SWEPCo | |
| | (in thousands) | |
TOTAL Contracts | | | | | | | | | | | | | | | | | | |
Beginning Balance in AOCI as of January 1, 2009 | | $ | (5,392 | ) | | $ | 1,531 | | | $ | (9,039 | ) | | $ | 3,650 | | | $ | (704 | ) | | $ | (5,924 | ) |
Changes in Fair Value Recognized in AOCI | | | 380 | | | | 118 | | | | 113 | | | | 399 | | | | (24 | ) | | | (112 | ) |
Amount of (Gain) or Loss Reclassified from AOCI to Income Statements/within Balance Sheets: | | | | | | | | | | | | | | | | | | | | | | | | |
Electric Generation, Transmission and Distribution Revenues | | | (251 | ) | | | (613 | ) | | | (504 | ) | | | (759 | ) | | | - | | | | - | |
Purchased Electricity for Resale | | | 462 | | | | 1,126 | | | | 926 | | | | 1,394 | | | | - | | | | - | |
Depreciation and Amortization Expense | | | - | | | | - | | | | (2 | ) | | | 1 | | | | - | | | | - | |
Interest Expense | | | 416 | | | | - | | | | 252 | | | | 23 | | | | 46 | | | | 207 | |
Regulatory Assets | | | 1,639 | | | | - | | | | 163 | | | | - | | | | - | | | | - | |
Regulatory Liabilities | | | (890 | ) | | | - | | | | (89 | ) | | | - | | | | - | | | | - | |
Ending Balance in AOCI as of March 31, 2009 | | $ | (3,636 | ) | | $ | 2,162 | | | $ | (8,180 | ) | | $ | 4,708 | | | $ | (682 | ) | | $ | (5,829 | ) |
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets at March 31, 2009 were:
Impact of Cash Flow Hedges on the Registrant Subsidiaries’
Condensed Balance Sheets
| | Hedging Assets (a) | | | Hedging Liabilities (a) | | | AOCI Gain (Loss) Net of Tax | |
| | Commodity | | | Interest Rate and Foreign Currency | | | Commodity | | | Interest Rate and Foreign Currency | | | Commodity | | | Interest Rate and Foreign Currency | |
Company | | (in thousands) | |
APCo | | $ | 6,807 | | | $ | - | | | $ | (559 | ) | | $ | - | | | $ | 4,066 | | | $ | (7,702 | ) |
CSPCo | | | 3,610 | | | | - | | | | (288 | ) | | | - | | | | 2,162 | | | | - | |
I&M | | | 3,494 | | | | - | | | | (283 | ) | | | - | | | | 2,091 | | | | (10,271 | ) |
OPCo | | | 4,474 | | | | 1,328 | | | | (371 | ) | | | (924 | ) | | | 2,669 | | | | 2,039 | |
PSO | | | - | | | | - | | | | (33 | ) | | | - | | | | (24 | ) | | | (658 | ) |
SWEPCo | | | - | | | | 1 | | | | (30 | ) | | | (301 | ) | | | (21 | ) | | | (5,808 | ) |
| | Expected to be Reclassified to Net Income During the Next Twelve Months | | | | |
| | Commodity | | | Interest Rate and Foreign Currency | | | Maximum Term for Exposure to Variability of Future Cash Flows | |
Company | | (in thousands) | | | (in months) | |
APCo | | $ | 3,939 | | | $ | (1,670 | ) | | | 14 | |
CSPCo | | | 2,095 | | | | - | | | | 14 | |
I&M | | | 2,024 | | | | (1,007 | ) | | | 14 | |
OPCo | | | 2,586 | | | | 273 | | | | 14 | |
PSO | | | (23 | ) | | | (183 | ) | | | 10 | |
SWEPCo | | | (21 | ) | | | (829 | | | | 44 | |
(a) | Hedging Assets and Hedging Liabilities are in included in Risk Management Assets and Liabilities on the Condensed Balance Sheets. |
The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes.
Credit Risk
The Registrant Subsidiaries limit credit risk in their wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. The Registrant Subsidiaries use Moody’s, S&P and current market-based qualitative and quantitative data to assess the financial health of counterparties on an ongoing basis. If an external rating is not available, an internal rating is generated utilizing a quantitative tool developed by Moody’s to estimate probability of default that corresponds to an implied external agency credit rating.
The Registrant Subsidiaries use standardized master agreements which may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit, and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a consolidated federal income tax return with their affiliatesfailure or inability to post collateral.
Collateral Triggering Events
Under a limited number of derivative and non-derivative counterparty contracts primarily related to pre-2002 risk management activities and under the tariffs of the RTOs and Independent System Operators (ISOs), the Registrant Subsidiaries are obligated to post an amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, the risk management organization assesses the appropriateness of these collateral triggering items in contracts. Management believes that a downgrade below investment grade is unlikely. The following table represents the Registrant Subsidiaries’ aggregate fair value of such contracts, the amount of collateral the Registrant Subsidiaries would have been required to post if the credit ratings had declined below investment grade and how much was attributable to RTO and ISO activities as of March 31, 2009.
| | Aggregate Fair Value Contracts | | | Amount of Collateral the Registrant Subsidiaries Would Have Been Required to Post | | | Amount Attributable to RTO and ISO Activities | |
Company | | (in thousands) | |
APCo | | $ | 38,664 | | | $ | 38,664 | | | $ | 38,220 | |
CSPCo | | | 20,506 | | | | 20,506 | | | | 20,270 | |
I&M | | | 19,845 | | | | 19,845 | | | | 19,617 | |
OPCo | | | 25,401 | | | | 25,401 | | | | 25,110 | |
PSO | | | 5,101 | | | | 5,101 | | | | 4,608 | |
SWEPCo | | | 6,012 | | | | 6,012 | | | | 5,431 | |
As of March 31, 2009, the Registrant Subsidiaries were not required to post any collateral.
FAIR VALUE MEASUREMENTS
SFAS 157 Fair Value Measurements
As described in the AEP System.2008 Annual Report, SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The allocationhierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurement) and the lowest priority to unobservable inputs (level 3 measurement). The Derivatives, Hedging and Fair Value Measurements note within the 2008 Annual Report should be read in conjunction with this report.
The following tables set forth by level within the fair value hierarchy the financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2009 and December 31, 2008. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the AEP System’s current consolidated federal income taxsignificance of a particular input to the AEP System companies allocatesfair value measurement requires judgment, and may affect the benefitvaluation of current tax losses tofair value assets and liabilities and their placement within the AEP System companies giving rise to such losses in determining their current tax expense. fair value hierarchy levels.
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of March 31, 2009
APCo | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Other Cash Deposits (d) | | $ | 421 | | | $ | - | | | $ | - | | | $ | 51 | | | $ | 472 | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | | 18,217 | | | | 912,180 | | | | 16,344 | | | | (825,771 | ) | | | 120,970 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 8,663 | | | | - | | | | (1,856 | ) | | | 6,807 | |
Dedesignated Risk Management Contracts (b) | | | - | | | | - | | | | - | | | | 12,189 | | | | 12,189 | |
Total Risk Management Assets | | | 18,217 | | | | 920,843 | | | | 16,344 | | | | (815,438 | ) | | | 139,966 | |
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 18,638 | | | $ | 920,843 | | | $ | 16,344 | | | $ | (815,387 | ) | | $ | 140,438 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 20,078 | | | $ | 876,231 | | | $ | 4,497 | | | $ | (836,745 | ) | | $ | 64,061 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 2,415 | | | | - | | | | (1,856 | ) | | | 559 | |
DETM Assignment (c) | | | - | | | | - | | | | - | | | | 4,527 | | | | 4,527 | |
Total Risk Management Liabilities | | $ | 20,078 | | | $ | 878,646 | | | $ | 4,497 | | | $ | (834,074 | ) | | $ | 69,147 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of December 31, 2008
APCo | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Other Cash Deposits (d) | | $ | 656 | | | $ | - | | | $ | - | | | $ | 52 | | | $ | 708 | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | | 16,105 | | | | 667,748 | | | | 11,981 | | | | (597,676 | ) | | | 98,158 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 6,634 | | | | - | | | | (1,413 | ) | | | 5,221 | |
Dedesignated Risk Management Contracts (b) | | | - | | | | - | | | | - | | | | 12,856 | | | | 12,856 | |
Total Risk Management Assets | | | 16,105 | | | | 674,382 | | | | 11,981 | | | | (586,233 | ) | | | 116,235 | |
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 16,761 | | | $ | 674,382 | | | $ | 11,981 | | | $ | (586,181 | ) | | $ | 116,943 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 18,808 | | | $ | 628,974 | | | $ | 3,972 | | | $ | (601,108 | ) | | $ | 50,646 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 2,545 | | | | - | | | | (1,413 | ) | | | 1,132 | |
DETM Assignment (c) | | | - | | | | - | | | | - | | | | 5,230 | | | | 5,230 | |
Total Risk Management Liabilities | | $ | 18,808 | | | $ | 631,519 | | | $ | 3,972 | | | $ | (597,291 | ) | | $ | 57,008 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of March 31, 2009
CSPCo | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Other Cash Deposits (d) | | $ | 20,036 | | | $ | - | | | $ | - | | | $ | 1,171 | | | $ | 21,207 | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | | 9,662 | | | | 481,211 | | | | 8,679 | | | | (435,732 | ) | | | 63,820 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 4,594 | | | | - | | | | (984 | ) | | | 3,610 | |
Dedesignated Risk Management Contracts (b) | | | - | | | | - | | | | - | | | | 6,465 | | | | 6,465 | |
Total Risk Management Assets | | | 9,662 | | | | 485,805 | | | | 8,679 | | | | (430,251 | ) | | | 73,895 | |
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 29,698 | | | $ | 485,805 | | | $ | 8,679 | | | $ | (429,080 | ) | | $ | 95,102 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 10,649 | | | $ | 462,306 | | | $ | 2,385 | | | $ | (441,545 | ) | | $ | 33,795 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 1,272 | | | | - | | | | (984 | ) | | | 288 | |
DETM Assignment (c) | | | - | | | | - | | | | - | | | | 2,401 | | | | 2,401 | |
Total Risk Management Liabilities | | $ | 10,649 | | | $ | 463,578 | | | $ | 2,385 | | | $ | (440,128 | ) | | $ | 36,484 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of December 31, 2008
CSPCo | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Other Cash Deposits (d) | | $ | 31,129 | | | $ | - | | | $ | - | | | $ | 1,171 | | | $ | 32,300 | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | | 9,042 | | | | 366,557 | | | | 6,724 | | | | (328,027 | ) | | | 54,296 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 3,725 | | | | - | | | | (794 | ) | | | 2,931 | |
Dedesignated Risk Management Contracts (b) | | | - | | | | - | | | | - | | | | 7,218 | | | | 7,218 | |
Total Risk Management Assets | | | 9,042 | | | | 370,282 | | | | 6,724 | | | | (321,603 | ) | | | 64,445 | |
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 40,171 | | | $ | 370,282 | | | $ | 6,724 | | | $ | (320,432 | ) | | $ | 96,745 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 10,559 | | | $ | 344,860 | | | $ | 2,227 | | | $ | (329,954 | ) | | $ | 27,692 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 1,429 | | | | - | | | | (794 | ) | | | 635 | |
DETM Assignment (c) | | | - | | | | - | | | | - | | | | 2,937 | | | | 2,937 | |
Total Risk Management Liabilities | | $ | 10,559 | | | $ | 346,289 | | | $ | 2,227 | | | $ | (327,811 | ) | | $ | 31,264 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of March 31, 2009
I&M | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 9,351 | | | $ | 470,390 | | | $ | 8,401 | | | $ | (425,852 | ) | | $ | 62,290 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 4,446 | | | | - | | | | (952 | ) | | | 3,494 | |
Dedesignated Risk Management Contracts (b) | | | - | | | | - | | | | - | | | | 6,256 | | | | 6,256 | |
Total Risk Management Assets | | | 9,351 | | | | 474,836 | | | | 8,401 | | | | (420,548 | ) | | | 72,040 | |
| | | | | | | | | | | | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | | | | | | | | | | | |
Cash and Cash Equivalents (e) | | | - | | | | 14,591 | | | | - | | | | 9,114 | | | | 23,705 | |
Debt Securities (f) | | | - | | | | 763,963 | | | | - | | | | - | | | | 763,963 | |
Equity Securities (g) | | | 418,876 | | | | - | | | | - | | | | - | | | | 418,876 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | | | 418,876 | | | | 778,554 | | | | - | | | | 9,114 | | | | 1,206,544 | |
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 428,227 | | | $ | 1,253,390 | | | $ | 8,401 | | | $ | (411,434 | ) | | $ | 1,278,584 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 10,306 | | | $ | 451,801 | | | $ | 2,309 | | | $ | (431,482 | ) | | $ | 32,934 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 1,236 | | | | - | | | | (953 | ) | | | 283 | |
DETM Assignment (c) | | | - | | | | - | | | | - | | | | 2,324 | | | | 2,324 | |
Total Risk Management Liabilities | | $ | 10,306 | | | $ | 453,037 | | | $ | 2,309 | | | $ | (430,111 | ) | | $ | 35,541 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of December 31, 2008
I&M | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 8,750 | | | $ | 357,405 | | | $ | 6,508 | | | $ | (319,857 | ) | | $ | 52,806 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 3,605 | | | | - | | | | (768 | ) | | | 2,837 | |
Dedesignated Risk Management Contracts (b) | | | - | | | | - | | | | - | | | | 6,985 | | | | 6,985 | |
Total Risk Management Assets | | | 8,750 | | | | 361,010 | | | | 6,508 | | | | (313,640 | ) | | | 62,628 | |
| | | | | | | | | | | | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | | | | | | | | | | | |
Cash and Cash Equivalents (e) | | | - | | | | 7,818 | | | | - | | | | 11,845 | | | | 19,663 | |
Debt Securities (f) | | | - | | | | 771,216 | | | | - | | | | - | | | | 771,216 | |
Equity Securities (g) | | | 468,654 | | | | - | | | | - | | | | - | | | | 468,654 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | | | 468,654 | | | | 779,034 | | | | - | | | | 11,845 | | | | 1,259,533 | |
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 477,404 | | | $ | 1,140,044 | | | $ | 6,508 | | | $ | (301,795 | ) | | $ | 1,322,161 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 10,219 | | | $ | 336,280 | | | $ | 2,156 | | | $ | (321,722 | ) | | $ | 26,933 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 1,383 | | | | - | | | | (768 | ) | | | 615 | |
DETM Assignment (c) | | | - | | | | - | | | | - | | | | 2,842 | | | | 2,842 | |
Total Risk Management Liabilities | | $ | 10,219 | | | $ | 337,663 | | | $ | 2,156 | | | $ | (319,648 | ) | | $ | 30,390 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of March 31, 2009
OPCo | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Other Cash Deposits (e) | | $ | 1,071 | | | $ | - | | | $ | - | | | $ | 1,674 | | | $ | 2,745 | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | | 11,968 | | | | 710,179 | | | | 10,793 | | | | (637,725 | ) | | | 95,215 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 7,021 | | | | - | | | | (1,219 | ) | | | 5,802 | |
Dedesignated Risk Management Contracts (b) | | | - | | | | - | | | | - | | | | 8,008 | | | | 8,008 | |
Total Risk Management Assets | | | 11,968 | | | | 717,200 | | | | 10,793 | | | | (630,936 | ) | | | 109,025 | |
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 13,039 | | | $ | 717,200 | | | $ | 10,793 | | | $ | (629,262 | ) | | $ | 111,770 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 13,191 | | | $ | 685,375 | | | $ | 2,991 | | | $ | (644,937 | ) | | $ | 56,620 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 2,514 | | | | - | | | | (1,219 | ) | | | 1,295 | |
DETM Assignment (c) | | | - | | | | - | | | | - | | | | 2,975 | | | | 2,975 | |
Total Risk Management Liabilities | | $ | 13,191 | | | $ | 687,889 | | | $ | 2,991 | | | $ | (643,181 | ) | | $ | 60,890 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of December 31, 2008
OPCo | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Other Cash Deposits (e) | | $ | 4,197 | | | $ | - | | | $ | - | | | $ | 2,431 | | | $ | 6,628 | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | | 11,200 | | | | 575,415 | | | | 8,364 | | | | (515,162 | ) | | | 79,817 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 4,614 | | | | - | | | | (983 | ) | | | 3,631 | |
Dedesignated Risk Management Contracts (b) | | | - | | | | - | | | | - | | | | 8,941 | | | | 8,941 | |
Total Risk Management Assets | | | 11,200 | | | | 580,029 | | | | 8,364 | | | | (507,204 | ) | | | 92,389 | |
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 15,397 | | | $ | 580,029 | | | $ | 8,364 | | | $ | (504,773 | ) | | $ | 99,017 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 13,080 | | | $ | 550,278 | | | $ | 2,801 | | | $ | (517,548 | ) | | $ | 48,611 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 1,770 | | | | - | | | | (983 | ) | | | 787 | |
DETM Assignment (c) | | | - | | | | - | | | | - | | | | 3,637 | | | | 3,637 | |
Total Risk Management Liabilities | | $ | 13,080 | | | $ | 552,048 | | | $ | 2,801 | | | $ | (514,894 | ) | | $ | 53,035 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of March 31, 2009
PSO | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 4,031 | | | $ | 43,779 | | | $ | 11 | | | $ | (39,589 | ) | | $ | 8,232 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 4,471 | | | $ | 41,387 | | | $ | 10 | | | $ | (39,982 | ) | | $ | 5,886 | |
Cash Flow Hedges (a) | | | - | | | | 33 | | | | - | | | | - | | | | 33 | |
DETM Assignment (c) | | | - | | | | - | | | | - | | | | 168 | | | | 168 | |
Total Risk Management Liabilities | | $ | 4,471 | | | $ | 41,420 | | | $ | 10 | | | $ | (39,814 | ) | | $ | 6,087 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of December 31, 2008
PSO | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 3,295 | | | $ | 39,866 | | | $ | 8 | | | $ | (36,422 | ) | | $ | 6,747 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 3,664 | | | $ | 37,835 | | | $ | 10 | | | $ | (36,527 | ) | | $ | 4,982 | |
DETM Assignment (c) | | | - | | | | - | | | | - | | | | 149 | | | | 149 | |
Total Risk Management Liabilities | | $ | 3,664 | | | $ | 37,835 | | | $ | 10 | | | $ | (36,378 | ) | | $ | 5,131 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of March 31, 2009
SWEPCo | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 4,751 | | | $ | 64,116 | | | $ | 18 | | | $ | (57,779 | ) | | $ | 11,106 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 59 | | | | - | | | | (58 | ) | | | 1 | |
Total Risk Management Assets | | $ | 4,751 | | | $ | 64,175 | | | $ | 18 | | | $ | (57,837 | ) | | $ | 11,107 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 5,270 | | | $ | 60,513 | | | $ | 16 | | | $ | (58,235 | ) | | $ | 7,564 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 389 | | | | - | | | | (58 | ) | | | 331 | |
DETM Assignment (c) | | | - | | | | - | | | | - | | | | 198 | | | | 198 | |
Total Risk Management Liabilities | | $ | 5,270 | | | $ | 60,902 | | | $ | 16 | | | $ | (58,095 | ) | | $ | 8,093 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis as of December 31, 2008
SWEPCo | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 3,883 | | | $ | 61,471 | | | $ | 14 | | | $ | (55,710 | ) | | $ | 9,658 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 107 | | | | - | | | | (80 | ) | | | 27 | |
Total Risk Management Assets | | $ | 3,883 | | | $ | 61,578 | | | $ | 14 | | | $ | (55,790 | ) | | $ | 9,685 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Contracts (a) | | $ | 4,318 | | | $ | 58,390 | | | $ | 17 | | | $ | (55,834 | ) | | $ | 6,891 | |
Cash Flow and Fair Value Hedges (a) | | | - | | | | 265 | | | | - | | | | (80 | ) | | | 185 | |
DETM Assignment (c) | | | - | | | | - | | | | - | | | | 175 | | | | 175 | |
Total Risk Management Liabilities | | $ | 4,318 | | | $ | 58,655 | | | $ | 17 | | | $ | (55,739 | ) | | $ | 7,251 | |
(a) | Amounts in “Other” column primarily represent counterparty netting of risk management contracts and associated cash collateral under FSP FIN 39-1. |
(b) | “Dedesignated Risk Management Contracts” are contracts that were originally MTM but were subsequently elected as normal under SFAS 133. At the time of the normal election, the MTM value was frozen and no longer fair valued. This will be amortized into revenues over the remaining life of the contract. |
(c) | See “Natural Gas Contracts with DETM” section of Note 15 in the 2008 Annual Report. |
(d) | Amounts in “Other” column primarily represent cash deposits with third parties. Level 1 amounts primarily represent investments in money market funds. |
(e) | Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 2 amounts primarily represent investments in money market funds. |
(f) | Amounts represent corporate, municipal and treasury bonds. |
(g) | Amounts represent publicly traded equity securities and equity-based mutual funds. |
The tax benefitfollowing tables set forth a reconciliation of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each companychanges in the consolidated group.fair value of net trading derivatives classified as level 3 in the fair value hierarchy:
| | APCo | | | CSPCo | | | I&M | | | OPCo | | | PSO | | | SWEPCo | |
Three Months Ended March 31, 2009 | | (in thousands) | |
Balance as of January 1, 2009 | | $ | 8,009 | | | $ | 4,497 | | | $ | 4,352 | | | $ | 5,563 | | | $ | (2 | ) | | $ | (3 | ) |
Realized (Gain) Loss Included in Net Income (or Changes in Net Assets) (a) | | | (3,898 | ) | | | (2,189 | ) | | | (2,118 | ) | | | (2,700 | ) | | | 3 | | | | 5 | |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | | - | | | | 3,264 | | | | - | | | | 4,045 | | | | - | | | | - | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
Purchases, Issuances and Settlements | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
Transfers in and/or out of Level 3 (b) | | | (74 | ) | | | (42 | ) | | | (40 | ) | | | (52 | ) | | | - | | | | - | |
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | | | 7,810 | | | | 764 | | | | 3,898 | | | | 946 | | | | - | | | | - | |
Balance as of March 31, 2009 | | $ | 11,847 | | | $ | 6,294 | | | $ | 6,092 | | | $ | 7,802 | | | $ | 1 | | | $ | 2 | |
| | APCo | | | CSPCo | | | I&M | | | OPCo | | | PSO | | | SWEPCo | |
Three Months Ended March 31, 2008 | | (in thousands) | |
Balance as of January 1, 2008 | | $ | (697 | ) | | $ | (263 | ) | | $ | (280 | ) | | $ | (1,607 | ) | | $ | (243 | ) | | $ | (408 | ) |
Realized (Gain) Loss Included in Net Income (or Changes in Net Assets) (a) | | | (657 | ) | | | (414 | ) | | | (391 | ) | | | (176 | ) | | | 29 | | | | 63 | |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) | | | - | | | | 721 | | | | - | | | | 1,639 | | | | - | | | | 106 | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
Purchases, Issuances and Settlements | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
Transfers in and/or out of Level 3 (b) | | | (1,026 | ) | | | (596 | ) | | | (572 | ) | | | (693 | ) | | | - | | | | - | |
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | | | 1,438 | | | | - | | | | 724 | | | | - | | | | 193 | | | | 204 | |
Balance as of March 31, 2008 | | $ | (942 | ) | | $ | (552 | ) | | $ | (519 | ) | | $ | (837 | ) | | $ | (21 | ) | | $ | (35 | ) |
(a) | Included in revenues on the Statements of Income. |
(b) | “Transfers in and/or out of Level 3” represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period. |
(c) | “Changes in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected on the Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets. |
The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2000. However, AEP has filed refund claims with the IRS for years 1997 through 2000 for the CSW pre-merger tax period, which are currently being reviewed. The Registrant Subsidiaries have completed the exam for the years 2001 through 20032006 and have issues that are being pursued at the appeals level. The returns for the years 2004 through 2006 are presently under audit by the IRS. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on net income.
The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine their tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions. Management believes that previously filed tax returns have positions that may be challenged by these tax authorities. However, management does not believe that the ultimate resolution of these audits will materially impact net income. With few exceptions, the Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2000.
Federal Tax Legislation – Affecting APCo, CSPCo and OPCo
In 2005, the Energy Tax Incentives Act of 2005 was signed into law. This act created a limited amount of tax credits for the building of IGCC plants. The credit is 20% of the eligible property in the construction of a new plant or 20% of the total cost of repowering of an existing plant using IGCC technology. In the case of a newly constructed IGCC plant, eligible property is defined as the components necessary for the gasification of coal, including any coal handling and gas separation equipment. AEP announced plans to construct two new IGCC plants that may be eligible for the allocation of these credits. AEP filed applications for the West Virginia and Ohio IGCC projects with the DOE and the IRS. Both projects were certified by the DOE and qualified by the IRS. However, neither project was allocated credits during the first round of credit awards. After one of the original credit recipients surrendered their credits in the Fall of 2007, the IRS announced a supplemental credit round for the Spring of 2008. AEP filed a new application in 2008 for the West Virginia IGCC project and in July 2008 the IRS allocated the project $134 million in credits. In September 2008, AEP entered into a memorandum of understanding with the IRS concerning the requirements of claiming the credits.
Federal Tax Legislation – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo
In October 2008, the Emergency Economic Stabilization Act of 2008 (the Act) was signed into law. The Act extended several expiring tax provisions and added new energy incentive provisions. The legislation impacted the availability of research credits, accelerated depreciation of smart meters, production tax credits and energy efficient commercial building deductions. Management has evaluated the impact of the law change and the application of the law change will not materially impact net income, cash flows or financial condition.
State Tax Legislation – Affecting APCo, CSPCo, I&M and OPCo
In March 2008, the Governor of West Virginia signed legislation providing for, among other things, a reduction in the West Virginia corporate income tax rate from 8.75% to 8.5% beginning in 2009. The corporate income tax rate could also be reduced to 7.75% in 2012 and 7% in 2013 contingent upon the state government achieving certain minimum levels of shortfall reserve funds. Management has evaluated the impact of the law change and the application of the law change will not materially impact net income, cash flows or financial condition.
9. FINANCING ACTIVITIES
Long-term Debt
Long-term debt and other securities issued, retired and principal payments made during the first ninethree months of 20082009 were:
| | | | Principal | | Interest | | Due |
Company | | Type of Debt | | Amount | | Rate | | Date |
| | | | (in thousands) | | (%) | | |
Issuances: | | | | | | | | | |
APCo | | Pollution Control Bonds | | $ | 40,000 | | 4.85 | | 2019 |
APCo | | Pollution Control Bonds | | | 30,000 | | 4.85 | | 2019 |
APCo | | Pollution Control Bonds | | | 75,000 | | Variable | | 2036 |
APCo | | Pollution Control Bonds | | | 50,275 | | Variable | | 2036 |
APCo | | Senior Unsecured Notes | | | 500,000 | | 7.00 | | 2038 |
CSPCo | | Senior Unsecured Notes | | | 350,000 | | 6.05 | | 2018 |
I&M | | Pollution Control Bonds | | | 25,000 | | Variable | | 2019 |
I&M | | Pollution Control Bonds | | | 52,000 | | Variable | | 2021 |
I&M | | Pollution Control Bonds | | | 40,000 | | 5.25 | | 2025 |
OPCo | | Pollution Control Bonds | | | 50,000 | | Variable | | 2014 |
OPCo | | Pollution Control Bonds | | | 50,000 | | Variable | | 2014 |
OPCo | | Pollution Control Bonds | | | 65,000 | | Variable | | 2036 |
OPCo | | Senior Unsecured Notes | | | 250,000 | | 5.75 | | 2013 |
SWEPCo | | Pollution Control Bonds | | | 41,135 | | 4.50 | | 2011 |
SWEPCo | | Senior Unsecured Notes | | | 400,000 | | 6.45 | | 2019 |
| | | | Principal | | Interest | | Due |
Company | | Type of Debt | | Amount Paid | | Rate | | Date |
| | | | (in thousands) | | (%) | | |
Retirements and Principal Payments: | | | | | | | | | |
APCo | | Pollution Control Bonds | | $ | 40,000 | | Variable | | 2019 |
APCo | | Pollution Control Bonds | | | 30,000 | | Variable | | 2019 |
APCo | | Pollution Control Bonds | | | 17,500 | | Variable | | 2021 |
APCo | | Pollution Control Bonds | | | 50,275 | | Variable | | 2036 |
APCo | | Pollution Control Bonds | | | 75,000 | | Variable | | 2037 |
APCo | | Senior Unsecured Notes | | | 200,000 | | 3.60 | | 2008 |
APCo | | Other | | | 11 | | 13.718 | | 2026 |
CSPCo | | Pollution Control Bonds | | | 48,550 | | Variable | | 2038 |
CSPCo | | Pollution Control Bonds | | | 43,695 | | Variable | | 2038 |
CSPCo | | Senior Unsecured Notes | | | 52,000 | | 6.51 | | 2008 |
CSPCo | | Senior Unsecured Notes | | | 60,000 | | 6.55 | | 2008 |
I&M | | Pollution Control Bonds | | | 45,000 | | Variable | | 2009 |
I&M | | Pollution Control Bonds | | | 25,000 | | Variable | | 2019 |
I&M | | Pollution Control Bonds | | | 52,000 | | Variable | | 2021 |
I&M | | Pollution Control Bonds | | | 50,000 | | Variable | | 2025 |
I&M | | Pollution Control Bonds | | | 40,000 | | Variable | | 2025 |
I&M | | Pollution Control Bonds | | | 50,000 | | Variable | | 2025 |
OPCo | | Pollution Control Bonds | | | 50,000 | | Variable | | 2014 |
OPCo | | Pollution Control Bonds | | | 50,000 | | Variable | | 2016 |
OPCo | | Pollution Control Bonds | | | 50,000 | | Variable | | 2022 |
OPCo | | Pollution Control Bonds | | | 35,000 | | Variable | | 2022 |
OPCo | | Pollution Control Bonds | | | 65,000 | | Variable | | 2036 |
OPCo | | Notes Payable | | | 1,463 | | 6.81 | | 2008 |
OPCo | | Notes Payable | | | 12,000 | | 6.27 | | 2009 |
PSO | | Pollution Control Bonds | | | 33,70 | | Variable | | 2014 |
SWEPCo | | Pollution Control Bonds | | | 41,135 | | Variable | | 2011 |
SWEPCo | | Notes Payable | | | 1,500 | | Variable | | 2008 |
SWEPCo | | Notes Payable | | | 3,304 | | 4.47 | | 2011 |
| | | | Principal | | Interest | | Due |
Company | | Type of Debt | | Amount | | Rate | | Date |
| | | | (in thousands) | | (%) | | |
Issuances: | | | | | | | | | |
APCo | | Senior Unsecured Notes | | $ | 350,000 | | 7.95 | | 2020 |
I&M | | Senior Unsecured Notes | | | 475,000 | | 7.00 | | 2019 |
I&M | | Pollution Control Bonds | | | 50,000 | | 6.25 | | 2025 |
I&M | | Pollution Control Bonds | | | 50,000 | | 6.25 | | 2025 |
PSO | | Pollution Control Bonds | | | 33,700 | | 5.25 | | 2014 |
| | | | Principal | | Interest | | Due |
Company | | Type of Debt | | Amount Paid | | Rate | | Date |
| | | | (in thousands) | | (%) | | |
Retirements and Principal Payments: | | | | | | | | | |
APCo | | Land Note | | $ | 4 | | 13.718 | | 2026 |
OPCo | | Notes Payable | | | 1,000 | | 6.27 | | 2009 |
OPCo | | Notes Payable | | | 3,500 | | 7.21 | | 2009 |
SWEPCo | | Notes Payable | | | 1,101 | | 4.47 | | 2011 |
In October 2008, SWEPCo retired $113January 2009, AEP Parent loaned I&M $25 million of 5.25%5.375% Notes Payable due in 2043.2010.
During 2008, the Registrant Subsidiaries chose to begin eliminating their auction-rate debt position due to market conditions. As of September 30, 2008,March 31, 2009, OPCo and SWEPCo had $218 million and $54 million, respectively, of tax-exempt long-term debt sold at auction rates (rates at contractual maximum rate of 13%) that reset every 35 days. These auction rates ranged from 11.117% to 13% for OPCo. SWEPCo’s rate was 4.353%. OPCo's $218 million ofOPCo’s debt relates to a lease structure with JMG that OPCo is unable to refinance atwithout their consent. The initial term for the JMG lease structure matures on March 31, 2010 and management is evaluating whether to terminate this time. In orderfacility prior to refinancematurity. Termination of this debt, OPCo needsfacility requires approval from the lessor's consent. This debt is insured by bond insurers previously AAA-rated, namely Ambac Assurance Corporation and Financial Guaranty Insurance Co. Due to the exposure that these bond insurersPUCO. As of March 31, 2009, SWEPCo had in connection with recent developments in the subprime credit market, the credit ratings of these 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, including many of the auctions$53.5 million of tax-exempt long-term debt. Consequently, the Registrant Subsidiaries chose to exit the auction-rate debt market.sold at auction rates (rate of 1.676%) that reset every 35 days. The instruments under which the bonds are issued allow for conversionus to convert to other short-term variable-rate structures, term-put structures and fixed-rate structures. Through September 30, 2008,
During the first quarter of 2009, I&M and PSO issued $100 million of 6.25% Pollution Control Bonds due in 2025 and $33.7 million of 5.25% Pollution Control Bonds due in 2014, respectively, which were previously held by trustees on the Registrant Subsidiaries reduced their outstanding auction rate securities. Management plans to continue this conversion and refunding process for the remaining $272 million to other permitted modes, including term-put structures, variable-rate and fixed-rate structures, as opportunities arise.
Subsidiaries’ behalf. As of September 30, 2008, $367March 31, 2009, trustees held, on the Registrant Subsidiaries’ behalf, $195 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% and $333 million was issued at fixed rates ranging from 4.5% to 5.25%. As of September 30, 2008, trustees held, on behalf of the Registrant Subsidiaries, approximately $330 million of theirremaining reacquired auction rateauction-rate tax-exempt long-term debt which management plansthe Registrant Subsidiaries plan to reissue to the public as market conditions permit. The following table shows the current status of debt which was issued as auction rate debt at December 31, 2007:
| | | | Remarketed at | | | | Remarketed at | | | | Remains at | | |
| | | | Fixed Rates | | | | Variable Rates | | Variable Rate | | Auction Rate | | Held by |
| | | | During the First | | Fixed Rate at | | During the First | | at | | at | | Trustee at |
| | Retired in | | Nine Months of | | September 30, | | Nine Months of | | September 30, | | September 30, | | September 30, |
| | 2008 | | 2008 | | 2008 | | 2008 | | 2008 | | 2008 | | 2008 |
Company | | (in thousands) | | | | (in thousands) | | | | | (in thousands) |
APCo | | $ | - | | $ | 30,000 | | 4.85% | | $ | 75,000 | | | 8.00% | | $ | - | | $ | 17,500 |
APCo | | | - | | | 40,000 | | 4.85% | | | 50,275 | | | 8.05% | | | - | | | - |
CSPCo | | | - | | | 56,000 | | 5.10% | | | - | | | - | | | - | | | 92,245 |
CSPCo | | | - | | | 44,500 | | 4.85% | | | - | | | - | | | - | | | - |
I&M | | | 45,000 | | | 40,000 | | 5.25% | | | 52,000 | | | 7.75% | | | - | | | 100,000 |
I&M | | | - | | | - | | - | | | 25,000 | | | 8.25% | | | - | | | - |
OPCo | | | - | | | - | | - | | | 65,000 | | | 6.50% | | | 218,000 | | | 85,000 |
OPCo | | | - | | | - | | - | | | 50,000 | | | 7.83% | | | - | | | - |
OPCo | | | - | | | - | | - | | | 50,000 | | | 7.50% | | | - | | | - |
PSO | | | - | | | - | | - | | | - | | | - | | | - | | | 33,700 |
SWEPCo | | | - | | | 81,700 | | 4.95% | | | - | | | - | | | 53,500 | | | - |
SWEPCo | | | - | | | 41,135 | | 4.50% | | | - | | | - | | | - | | | - |
| | | | | | | | | | | | | | | | | | | | |
Total | | $ | 45,000 | | $ | 333,335 | | | | $ | 367,275 | | | | | $ | 271,500 | | $ | 328,445 |
Lines of CreditUtility Money Pool – AEP System
The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of its subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries. The AEP System corporate borrowing programUtility Money Pool operates in accordance with the terms and conditions approved in a regulatory order. The amount of outstanding loans (borrowings) to/from the Utility Money Pool as of September 30, 2008March 31, 2009 and December 31, 20072008 are included in Advances to/from Affiliates on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the ninethree months ended September 30, 2008March 31, 2009 are described in the following table:
| | | | | | | | | | Loans | | | |
| | Maximum | | Maximum | | Average | | Average | | (Borrowings) | | Authorized | |
| | Borrowings | | Loans to | | Borrowings | | Loans to | | to/from Utility | | Short-Term | |
| | from Utility | | Utility | | from Utility | | Utility Money | | Money Pool as of | | Borrowing | |
| | Money Pool | | Money Pool | | Money Pool | | Pool | | September 30, 2008 | | Limit | |
Company | | (in thousands) | |
APCo | | | $ | 307,226 | | | $ | 269,987 | | | $ | 188,985 | | | $ | 187,192 | | | $ | (93,558 | ) | | $ | 600,000 | |
CSPCo | | | | 238,172 | | | | 150,358 | | | | 157,569 | | | | 53,962 | | | | 21,833 | | | | 350,000 | |
I&M | | | | 345,064 | | | | - | | | | 195,582 | | | | - | | | | (224,071 | ) | | | 500,000 | |
OPCo | | | | 415,951 | | | | 82,486 | | | | 174,840 | | | | 64,127 | | | | 39,758 | | | | 600,000 | |
PSO | | | | 149,278 | | | | 59,384 | | | | 72,688 | | | | 29,811 | | | | (125,029 | ) | | | 300,000 | |
SWEPCo | | | | 168,495 | | | | 300,525 | | | | 87,426 | | | | 219,159 | | | | 195,628 | | | | 350,000 | |
| | | | | | | | | Loans | | | |
| Maximum | | Maximum | | Average | | Average | | (Borrowings) | | Authorized | |
| Borrowings | | Loans to | �� | Borrowings | | Loans to | | to/from Utility | | Short-Term | |
| from Utility | | Utility | | from Utility | | Utility Money | | Money Pool as of | | Borrowing | |
| Money Pool | | Money Pool | | Money Pool | | Pool | | March 31, 2009 | | Limit | |
Company | (in thousands) | |
APCo | | $ | 420,925 | | | $ | - | | | $ | 248,209 | | | $ | - | | | $ | (120,481 | ) | | $ | 600,000 | |
CSPCo | | | 203,306 | | | | - | | | | 135,532 | | | | - | | | | (177,736 | ) | | | 350,000 | |
I&M | | | 491,107 | | | | 22,979 | | | | 153,707 | | | | 16,201 | | | | (16,421 | ) | | | 500,000 | |
OPCo | | | 406,354 | | | | - | | | | 281,950 | | | | - | | | | (320,166 | ) | | | 600,000 | |
PSO | | | 77,976 | | | | 87,443 | | | | 58,549 | | | | 46,483 | | | | 7,009 | | | | 300,000 | |
SWEPCo | | | 62,871 | | | | 63,539 | | | | 30,880 | | | | 29,381 | | | | 37,649 | | | | 350,000 | |
The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:
| | Nine Months Ended September 30, | | | Three Months Ended March 31, |
| | 2008 | | | 2007 | | | 2009 | | 2008 |
Maximum Interest Rate | | | 5.37 | % | | | 5.94 | % | | 2.28% | | 5.37% |
Minimum Interest Rate | | | 2.91 | % | | | 5.30 | % | | 1.22% | | 3.39% |
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the ninethree months ended September 30,March 31, 2009 and 2008 and 2007 are summarized for all Registrant Subsidiaries in the following table:
| | Average Interest Rate for Funds | | | Average Interest Rate for Funds | |
| | Borrowed from | | | Loaned to | |
| | the Utility Money Pool for the | | | the Utility Money Pool for the | |
| | Nine Months Ended September 30, | | | Nine Months Ended September 30, | |
| | 2008 | | | 2007 | | | 2008 | | | 2007 | |
Company | | | | | | | | | | | | |
APCo | | | 3.62 | % | | | 5.41 | % | | | 3.25 | % | | | 5.84 | % |
CSPCo | | | 3.66 | % | | | 5.48 | % | | | 2.99 | % | | | 5.39 | % |
I&M | | | 3.19 | % | | | 5.38 | % | | | - | % | | | 5.84 | % |
OPCo | | | 3.24 | % | | | 5.39 | % | | | 3.62 | % | | | 5.43 | % |
PSO | | | 3.04 | % | | | 5.47 | % | | | 4.53 | % | | | - | % |
SWEPCo | | | 3.36 | % | | | 5.54 | % | | | 3.01 | % | | | 5.34 | % |
| | Average Interest Rate for Funds | | | Average Interest Rate for Funds |
| | Borrowed from the Utility Money | | | Loaned to the Utility Money |
| | Pool for the | | | Pool for the |
| | Three Months Ended March 31, | | | Three Months Ended March 31, |
| | 2009 | | 2008 | | | 2009 | | 2008 |
Company | | |
APCo | | 1.76% | | 4.21% | | | -% | | 3.46% |
CSPCo | | 1.62% | | 4.01% | | | -% | | -% |
I&M | | 1.86% | | 3.99% | | | 1.76% | | -% |
OPCo | | 1.65% | | 4.29% | | | -% | | -% |
PSO | | 2.01% | | 3.51% | | | 1.63% | | 4.57% |
SWEPCo | | 1.86% | | 4.00% | | | 1.68% | | -% |
Short-term Debt
The Registrant Subsidiaries’ outstanding short-term debt was as follows:
| | | | September 30, 2008 | | December 31, 2007 |
| | | | Outstanding | | Interest | | Outstanding | | Interest |
| | Type of Debt | | Amount | | Rate (a) | | Amount | | Rate (a) |
Company | | | | (in thousands) | | | | (in thousands) | | |
OPCo | | Commercial Paper – JMG (b) | | $ | - | | -% | | $ | 701 | | 5.35% |
SWEPCo | | Line of Credit – Sabine Mining Company (c) | | | 9,520 | | 7.75% | | | 285 | | 5.25% |
| | | | March 31, 2009 | | December 31, 2008 |
| | | | | | Weighted | | | | Weighted |
| | | | | | Average | | | | Average |
| | | | Outstanding | | Interest | | Outstanding | | Interest |
| | Type of Debt | | Amount | | Rate | | Amount | | Rate |
Company | | | | (in thousands) | | | | (in thousands) | | |
SWEPCo | | Line of Credit – Sabine Mining Company (a) | | $ | 6,559 | | 1.82% | | $ | 7,172 | | 1.54% |
(a) | Weighted average rate. |
(b) | This commercial paper is specifically associated with the Gavin Scrubber and is backed by a separate credit facility. |
(c) | Sabine Mining Company is consolidated under FIN 46R. |
Credit Facilities
In April 2008, theThe Registrant Subsidiaries and certain other companies in the AEP System entered intohave 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, letters of credit may be issued. In April 2009, the $350 million 364-day credit agreement expired. As of September 30, 2008,March 31, 2009, $372 million of letters of credit were issued by Registrant Subsidiaries under the $650 million 3-year credit agreement to support variable rate demand notes.Pollution Control Bonds as follow:
| Letters of Credit | |
| Amount Outstanding | |
| Against $650 million | |
| 3-Year Agreement | |
Company | (in thousands) | |
APCo | | $ | 126,716 | |
I&M | | | 77,886 | |
OPCo | | | 166,899 | |
The following is a combined presentation of certain components of the registrants’Registrant Subsidiaries’ management’s discussion and analysis. The information in this section completes the information necessary for management’s discussion and analysis of financial condition and net income and is meant to be read with (i) Management’s Financial Discussion and Analysis, (ii) financial statements and (iii) footnotes of each individual registrant. The combined Management’s Discussion and Analysis of Registrant Subsidiaries section of the 20072008 Annual Report should also be read in conjunction with this report.
Market ImpactsEconomic Slowdown
In recent months,The financial struggles of the world and U.S. economies have experienced significant slowdowns. These economic slowdowns have impacted and willeconomy continue to impact the Registrant Subsidiaries’ industrial sales as well as sales opportunities in the wholesale market. Industrial sales in various sections of the service territories are decreasing due to reduced shifts and suspended operations by some of the Registrant Subsidiaries’ large industrial customers. Although many sections of the Registrant Subsidiaries’ service territories are experiencing slowdowns in new construction, their residential and commercial and industrial sales. Concurrently,customer base appears to be stable. As a result of these economic issues, management is currently monitoring the following:
· | Margins from Off-system Sales – Margins from off-system sales for the AEP System continue to decrease due to reductions in sales volumes and weak market power prices, reflecting reduced overall demand for electricity. Management currently forecasts that margins from off-system volumes will decrease by approximately 30% in 2009. These trends will most likely continue until the economy rebounds and electricity demand and prices increase. |
· | Industrial KWH Sales – The AEP System’s industrial KWH sales for the quarter ended March 31, 2009 were down 15% in comparison to the quarter ended March 31, 2008. Approximately half of this decrease was due to cutbacks or closures by customers who produce primary metals served by APCo, CSPCo, I&M, OPCo and SWEPCo. I&M, PSO and SWEPCo also experienced additional significant decreases in KWH sales to customers in the plastics, rubber and paper manufacturing industries. Since the AEP System’s trends for industrial sales are usually similar to the nation’s industrial production, these trends will continue until industrial production improves. |
· | Risk of Loss of Major Customers – Management monitors the financial strength and viability of each major industrial customer individually. The Registrant Subsidiaries have factored this analysis into their operational planning. CSPCo’s and OPCo’s largest customer, Ormet, with a 520 MW load, recently announced that it is in dispute with its sole customer which could potentially force Ormet to halt production. In February 2009, Century Aluminum, a major industrial customer (325 MW load) of APCo, announced the curtailment of operations at its Ravenswood, WV facility. |
Credit Markets
The financial markets have become increasingly unstable and constrainedremain volatile at both a global and domestic level. This systemic marketplace distress is impactingcould impact the Registrant Subsidiaries’ access to capital, liquidity asset valuations in trust funds, creditworthy status of customers, suppliers and trading partners and cost of capital. AEP’s financial staff actively manages these factors with oversight from the risk committee. The uncertainties in the creditcapital markets could have significant implications since the Registrant Subsidiaries rely on continuing access to capital to fund operations and capital expenditures.
The current credit markets are constrainingManagement believes that the Registrant Subsidiaries’ abilitySubsidiaries have adequate liquidity, through the Utility Money Pool and cash flows from their operations, to issue new debtsupport planned business operations and refinance existing debt. Approximately $120 million and $300 million of AEP Consolidated’s $16 billion of long-term debt as of September 30, 2008 will mature in the remainder of 2008 and 2009, respectively. I&M and OPCo have $50 million and $37 million, respectively, maturing in 2008. APCo, OPCo and PSO have $150 million, $82 million and $50 million, respectively, maturing incapital expenditures through 2009. Management intends to refinance these maturities. To support its operations, AEP has $3.9 billion in aggregate credit facility commitments.commitments as of March 31, 2009. These commitments include 27 different banks with no one bank having more than 10% of the total bank commitments. Short-term funding for the Registrant Subsidiaries comes from AEP’s commercial paper program credit facilities which supportssupport the Utility Money Pool. In September 2008APCo, OPCo and October 2008, AEP borrowed $600PSO have $150 million, $73 million and $1.4 billion,$50 million, respectively, undermaturing in the credit facilitiesremainder of 2009. Long-term debt of $200 million, $150 million, $680 million and $150 million will mature in 2010 for APCo, CSPCo, OPCo and PSO, respectively. Management intends to enhance its cash position during this period of market disruptions. This money can be loaned to the Registrant Subsidiaries through the Utility Money Pool.
refinance debt maturities. Management cannot predict the length of time the current credit situation will continue or its impact on future operations and the Registrant Subsidiaries’ ability to issue debt at reasonable interest rates. However, when market conditions improve, management plans to repay the amounts drawn under the credit facilities, re-enter the commercial paper market and issue long-term debt. If there is not an improvement in access to capital, management believes that the Registrant Subsidiaries have adequate liquidity, through the Utility Money Pool, to support their planned business operations and construction programs through 2009.
AEP hassponsors several trust funds with significant investments in several trust fundsintended to provide for future payments of pensions and OPEB. I&M has significant investments in several trust funds intended to provide for future payments of nuclear decommissioning and spent nuclear fuel disposal. AllAlthough all of the trust funds’ investments are well-diversified and managed in compliance with all laws and regulations. Theregulations, the value of the investments in these trusts has declined substantially over the past year due to the decreases in thedomestic and international 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, theThe decline in pension asset values will not require the AEP System to make a contribution under ERISA in 2009. As of March 31, 2009, management estimates that the minimum contributions to the pension trust will be made$475 million in 2008 or 2009.2010 and $283 million in 2011. These amounts are allocated to companies in the AEP System, including the Registrant Subsidiaries. However, estimates may vary significantly based on market returns, changes in actuarial assumptions and other factors.
On behalf of the Registrant Subsidiaries, AEPSC enters into risk management contracts with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, exposures change daily. AEP’s risk management organization monitors these exposures on a daily basis to limit the Registrant Subsidiaries’ economic and financial statement impact on a counterparty basis.
Budgeted Construction Expenditures
Budgeted construction expenditures for the Registrant Subsidiaries for 2010 are:
| | Budgeted | |
| | Construction | |
| | Expenditures | |
Company | | (in millions) | |
APCo | | $ | 297 | |
CSPCo | | | 231 | |
I&M | | | 246 | |
OPCo | | | 294 | |
PSO | | | 162 | |
SWEPCo | | | 423 | |
Budgeted 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.
LIQUIDITY
Sources of Funding
Short-term funding for the Registrant Subsidiaries comes from AEP’s commercial paper program and revolving credit facilities through the Utility Money Pool. AEP and its Registrant Subsidiaries also operate a money pool to minimize the AEP System’s external short-term funding requirements and sell accounts receivable to provide liquidity. The credit facilities that support the Utility Money Pool were reduced by Lehman Brothers Holdings Inc.’s commitment amount of $46 million following its bankruptcy. In March 2008, these credit facilities were amended so that $750 million may be issued under each credit facility as letters of credit (LOC). Certain companies within the AEP System including the Registrant Subsidiaries operate the Utility Money Pool to minimize external short-term funding requirements. The Registrant Subsidiaries also sell accounts receivable to provide liquidity. The Registrant Subsidiaries generally use short-term funding sources (the Utility Money Pool or receivables sales) to provide for interim financing of capital expenditures that exceed internally generated funds and periodically reduce their outstanding short-term debt through issuances of long-term debt, sale-leaseback,sale-leasebacks, leasing arrangements and additional capital contributions from AEP.Parent.
In April 2008, the Registrant Subsidiaries and certain other companies in the AEP System 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. Management chose to allow the $350 million credit agreement to expire in April 2009. The Registrant Subsidiaries may issue LOCs under the credit facilities.facility. Each subsidiary has a borrowing/LOC limit under the credit facilities.facility. As of September 30, 2008,March 31, 2009, a total of $372 million of LOCs were issued under the 3-year credit agreement to support variable rate demand notes. The following table shows each Registrant Subsidiaries’ borrowing/LOC limit under eachthe credit facility and the outstanding amount of LOCs for the $650 million facility.LOCs.
| | | | | | LOC Amount | |
| | | | | | Outstanding | |
| | | | | | Against | |
| | | | | | $650 million | |
| | Credit Facility | | | | Agreement at | |
| | | | | | September 30, 2008 | |
Company | | (in millions) | |
APCo | | | $ | 300 | | | $ | 150 | | | $ | 127 | |
CSPCo | | | | 230 | | | | 120 | | | | - | |
I&M | | | | 230 | | | | 120 | | | | 78 | |
OPCo | | | | 400 | | | | 200 | | | | 167 | |
PSO | | | | 65 | | | | 35 | | | | - | |
SWEPCo | | | | 230 | | | | 120 | | | | - | |
| | | LOC Amount | |
| | | Outstanding | |
| $650 million | | Against | |
| Credit Facility | | $650 million | |
| Borrowing/LOC | | Agreement at | |
| Limit | | March 31, 2009 | |
Company | (in millions) | |
APCo | | $ | 300 | | | $ | 127 | |
CSPCo | | | 230 | | | | - | |
I&M | | | 230 | | | | 78 | |
OPCo | | | 400 | | | | 167 | |
PSO | | | 65 | | | | - | |
SWEPCo | | | 230 | | | | - | |
At September 30, 2008, there were no outstanding amounts under the $350 million facility.Dividend Restrictions
Credit Markets
ToUnder the extent financing is unavailable due to the challenging credit markets,Federal Power Act, the Registrant Subsidiaries will rely upon cash flowsare restricted from operations and access to the Utility Money Pool to fund their debt maturities, continuing operations and capital expenditures.paying dividends out of stated capital.
Sale of Receivables Through AEP Credit
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. Consequently, management chose to exit the auction-rate debt market. As of September 30, 2008, OPCo had $218 million (rates range from 11.117% to 13%) and SWEPCo had $54 million (rate of 4.353%) outstanding of tax-exempt long-term debt sold at auction rates that reset every 35 days. Approximately $218 million of this debt relates to a lease structure with JMG that OPCo is unable to refinance at this time. In order to refinance this debt, OPCo needs the lessor's consent. This debt is insured by previously AAA-rated bond insurers. The instruments under which the bonds are issued allow for their conversion to other short-term variable-rate structures, term-put structures and fixed-rate structures. Management plans to continue the conversion and refunding process to other permitted modes, including term-put structures, variable-rate and fixed-rate structures, as opportunities arise. Through September 30, 2008, the Registrant Subsidiaries reduced their outstanding auction rate securities.
As of September 30, 2008, trustees held, on behalf of the Registrant Subsidiaries, approximately $330 million of their reacquired auction rate tax-exempt long-term debt which management plans to reissue to the public as the market permits. The following table shows the current status of debt that was issued as auction rate at December 31, 2007 by Registrant Subsidiary.
| | | | Remarketed at | | | | | |
| | | | Fixed or | | Remains in | | Held | |
| | Retired | | Variable Rates | | Auction Rate at | | by Trustee at | |
| | in 2008 | | During 2008 | | September 30, 2008 | | September 30, 2008 | |
Company | | (in millions) | |
APCo | | | $ | - | | | $ | 195 | | | $ | - | | | $ | 18 | |
CSPCo | | | | - | | | | 101 | | | | - | | | | 92 | |
I&M | | | | 45 | | | | 117 | | | | - | | | | 100 | |
OPCo | | | | - | | | | 165 | | | | 218 | | | | 85 | |
PSO | | | | - | | | | - | | | | - | | | | 34 | |
SWEPCo | | | | - | | | | 123 | | | | 54 | | | | - | |
APCo, I&M and OPCo issued $125 million, $77 million and $165 million, respectively, of weekly variable rate debt. As of September 30, 2008, the variable rates ranged from 6.5% to 8.25%. APCo issued fixed rate debt of $70 million at 4.85% until 2019. CSPCo issued fixed rate debt of $45 million at 4.85% until 2012 and $56 million at 5.1% until 2013. I&M issued $40 million of fixed rate debt at 5.25% due 2025. SWEPCo remarketed $82 million of fixed rate debt at 4.95% due 2018 and issued $41 million of fixed rate debt at 4.5% through 2011.
Sales of Receivable Agreement
In October 2008, AEP Credit renewed its $600 million sale of receivables agreement through October 2009. The sale of receivables agreement provides a commitment of $700 million from banks and commercial paper conduits to purchase receivables from AEP Credit. Management intends to extend or replace the sale of receivables agreement. At March 31, 2009, $578 million of commitments to purchase accounts receivable were outstanding under the receivables agreement. AEP Credit purchases accounts receivable from the Registrant Subsidiaries.
Capital Expenditures
Due to recent credit market instability, management is currently reviewing projections for capital expenditures for 2009 through 2010. Management plans to identify reductions of approximately $750 million for 2009 across the AEP System. Management is evaluating possible additional capital reductions for 2010. Management is also reviewing projections for operation and maintenance expense. Management's intent is to keep operation and maintenance expense flat in 2009 as compared to 2008.
Significant FactorsSIGNIFICANT FACTORS
Ohio Electric Security Plan Filings
In March 2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s ESPs which will be in effect through 2011. The ESP order authorized increases to revenues during the ESP period and capped the overall revenue increases through a phase-in of the fuel adjustment clause (FAC). The ordered increases for CSPCo are 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo are 8% in 2009, 7% in 2010 and 8% in 2011. After final PUCO review and approval of conforming rate schedules, CSPCo and OPCo implemented rates for the April 2009 billing cycle. CSPCo and OPCo will collect the 2009 annualized revenue increase over the remainder of 2009.
The order provides a FAC for the three-year period of the ESP. The FAC increase will be phased in to meet the ordered annual caps described above. The FAC increase before phase-in will be subject to quarterly true-ups to actual recoverable FAC costs and to annual accounting audits and prudency reviews. The order allows CSPCo and OPCo to defer unrecovered FAC costs resulting from the annual caps/phase-in plan and to accrue carrying charges on such deferrals at CSPCo’s and OPCo’s weighted average cost of capital. The deferred FAC balance at the end of the ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018. As of March 31, 2009, the FAC deferral balances were $17 million and $66 million for CSPCo and OPCo, respectively, including carrying charges. The PUCO rejected a proposal by several intervenors to offset the FAC costs with a credit for off-system sales margins. As a result, CSPCo and OPCo will retain the benefit of their share of the AEP System’s off-system sales. In addition, the ESP order provided for both the FAC deferral credits and the off-system sales margins to be excluded from the methodology for the Significantly Excessive Earnings Test (SEET). The SEET is discussed below.
Additionally, the order addressed several other items, including:
· | The approval of new distribution riders, subject to true-up for recovery of costs for enhanced vegetation management programs for CSPCo and OPCo and the proposed gridSMART advanced metering initial program roll out in a portion of CSPCo’s service territory. The PUCO proposed that CSPCo mitigate the costs of gridSMART by seeking matching funds under the American Recovery and Reinvestment Act of 2009. As a result, a rider was established to recover 50% or $32 million of the projected $64 million revenue requirement related to gridSMART costs. The PUCO denied the other distribution system reliability programs proposed by CSPCo and OPCo as part of their ESP filings. The PUCO decided that those requests should be examined in the context of a complete distribution base rate case. The order did not require CSPCo and/or OPCo to file a distribution base rate case. |
· | The approval of CSPCo’s and OPCo’s request to recover the incremental carrying costs related to environmental investments made from 2001 through 2008 that are not reflected in existing rates. Future recovery during the ESP period of incremental carrying charges on environmental expenditures incurred beginning in 2009 may be requested in annual filings. |
· | The approval of a $97 million and $55 million increase in CSPCo’s and OPCo’s Provider of Last Resort charges, respectively, to compensate for the risk of customers changing electric suppliers during the ESP period. |
· | The requirement that CSPCo’s and OPCo’s shareholders fund a combined minimum of $15 million in costs over the ESP period for low-income, at-risk customer programs. This funding obligation was recognized as a liability and an unfavorable adjustment to Other Operation and Maintenance expense for the three-month period ending March 31, 2009. |
· | The deferral of CSPCo’s and OPCo’s request to recover certain existing regulatory assets, including customer choice implementation and line extension carrying costs as part of the ESPs. The PUCO decided it would be more appropriate to consider this request in the context of CSPCo’s and OPCo’s next distribution base rate case. These regulatory assets, which were approved by prior PUCO orders, total $58 million for CSPCo and $40 million for OPCo as of March 31, 2009. In addition, CSPCo and OPCo would recover and recognize as income, when collected, $35 million and $26 million, respectively, of related unrecorded equity carrying costs incurred through March 2009. |
Finally, consistent with its decisions on ESP orders of other companies, the PUCO ordered its staff to convene a workshop to determine the methodology for the SEET that will be applicable to all electric utilities in Ohio. The SEET requires the PUCO to determine, following the end of each year of the ESP, if any rate adjustments included in the ESP resulted in excessive earnings as measured by whether the earned return on common equity of CSPCo and OPCo is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that have comparable business and financial risk. If the rate adjustments, in the aggregate, result in significantly excessive earnings in comparison, the PUCO must require that the amount of the excess be returned to customers. The PUCO’s decision on the SEET review of CSPCo’s and OPCo’s 2009 earnings is not expected to be finalized until the second or third quarter of 2010.
In March 2009, intervenors filed a motion to stay a portion of the ESP rates or alternately make that portion subject to refund because the intervenors believed that the ordered ESP rates for 2009 were retroactive and therefore unlawful. In March 2009, the PUCO approved CSPCo’s and OPCo’s tariffs effective with the April 2009 billing cycle and rejected the intervenors’ motion. The PUCO also clarified that the reference in its earlier order to the January 1, 2009 date related to the term of the ESP, not to the effective date of tariffs and clarified the tariffs were not retroactive. In March 2009, CSPCo and OPCo implemented the new ESP tariffs effective with the start of the April 2009 billing cycle. In April 2009, CSPCo and OPCo filed a motion requesting rehearing of several issues. In April 2009, several intervenors filed motions requesting rehearing of issues underlying the PUCO’s authorized rate increases and one intervenor filed a motion requesting the PUCO to direct CSPCo and OPCo to cease collecting rates under the order. Certain intervenors also filed a complaint for writ of prohibition with the Ohio legislature passed Senate Bill 221, which amendsSupreme Court to halt any further collection from customers of what the restructuring law effective July 31, 2008 and requires electric utilities to adjust their rates by filing an Electric Security Plan (ESP). Electric utilitiesintervenors claim is unlawful retroactive rate increases.
Management will evaluate whether it will withdraw the ESP applications after a final order, thereby terminating the ESP proceedings. If CSPCo and/or OPCo withdraw the ESP applications, CSPCo and/or OPCo 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, fromor another ESP as permitted by the date of its commencement, could transition CSPColaw. The revenues collected and OPCo to full market rates no sooner than six years and no later than ten years after therecorded in 2009 under this 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 operationsorder are not subject to cost-based rate regulation accounting. However, if a fuel cost recovery mechanism is implemented withinpossible refund through the ESP, CSPCo’s and OPCo’s fuel and purchased power operations would be subject to cost-based rate regulation accounting.SEET process. 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 relateddue 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. Failuredecision of the PUCO to ultimately approvedefer guidance on the recoverySEET methodology to a future generic SEET proceeding, to estimate the amount, if any, of a possible refund that could result from the regulatory assets would have an adverse effect on future net income and cash flows.SEET process in 2010.
New GenerationGeneration/Purchase Power Agreement
In 2008,2009, AEP completed or is in various stages of construction of the following generation facilities:
| | | | | | | | | | | | | | | | | Commercial |
| | | | | | Total | | | | | | | | | Nominal | | Operation |
Operating | | Project | | | | Projected | | | | | | | | | MW | | Date |
Company | | Name | | Location | | Cost (a) | | CWIP (b) | | Fuel Type | | Plant Type | | Capacity | | (Projected) |
| | | | | | (in millions) | | (in millions) | | | | | | | | |
PSO | | Southwestern | (c) | Oklahoma | | $ | 56 | | $ | - | | Gas | | Simple-cycle | | 150 | | 2008 |
PSO | | Riverside | (d) | Oklahoma | | | 58 | | | - | | Gas | | Simple-cycle | | 150 | | 2008 |
AEGCo | | Dresden | (e) | Ohio | | | 309 | (e) | | 149 | | Gas | | Combined-cycle | | 580 | | 2010(h) |
SWEPCo | | Stall | | Louisiana | | | 378 | | | 158 | | Gas | | Combined-cycle | | 500 | | 2010 |
SWEPCo | | Turk | (f) | Arkansas | | | 1,522 | (f) | | 448 | | Coal | | Ultra-supercritical | | 600 | (f) | 2012 |
APCo | | Mountaineer | (g) | West Virginia | | | | (g) | | | | Coal | | IGCC | | 629 | | (g) |
CSPCo/OPCo | | Great Bend | (g) | Ohio | | | | (g) | | | | Coal | | IGCC | | 629 | | (g) |
| | | | | | | | | | | | | | | | | Commercial |
| | | | | | Total | | | | | | | | | Nominal | | Operation |
Operating | | Project | | | | Projected | | | | | | | | | MW | | Date |
Company | | Name | | Location | | Cost (a) | | CWIP (b) | | Fuel Type | | Plant Type | | Capacity | | (Projected) |
| | | | | | (in millions) | | (in millions) | | | | | | | | |
AEGCo | | Dresden | (c) | Ohio | | $ | 322 | | $ | 189 | | Gas | | Combined-cycle | | 580 | | 2013 | |
SWEPCo | | Stall | | Louisiana | | | 385 | | | 291 | | Gas | | Combined-cycle | | 500 | | 2010 | |
SWEPCo | | Turk | (d) | Arkansas | | | 1,628 | (d) | | 480 | | Coal | | Ultra-supercritical | | 600 | (d) | 2012 | |
APCo | | Mountaineer | (e) | West Virginia | | | | (e) | | | | Coal | | IGCC | | 629 | | | (e) |
CSPCo/OPCo | | Great Bend | (e) | Ohio | | | | (e) | | | | Coal | | IGCC | | 629 | | | (e) |
(a) | Amount excludes AFUDC. |
(b) | Amount includes AFUDC. |
(c) | Southwestern Units were placed in service on February 29, 2008. |
(d) | The final Riverside Unit was placed in service on June 15, 2008. |
(e) | In September 2007, AEGCo purchased the partially completed Dresden plant from Dresden Energy LLC, a subsidiary of Dominion Resources, Inc., for $85 million, which is included in the “Total Projected Cost” section above. |
(f)(d) | SWEPCo plans to own approximately 73%, or 440 MW, totaling $1.1$1.2 billion in capital investment. The increase in the cost estimate disclosed in the 2007 Annual Report relates to cost escalations due to the delay in receipt of permits and approvals. See “Turk Plant” section below. |
(g)(e) | Construction of IGCC plants are pending necessary permits andis subject to regulatory approval.approvals. See “IGCC Plants” section below. |
(h) | Projected completion date of the Dresden Plant is currently under review. To the extent that the completion date is delayed, the total projected cost of the Dresden Plant could change. |
Turk Plant
In November 2007, the APSC granted approval to build the Turk Plant. Certain landowners filed a notice of appealhave appealed the APSC’s decision 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 $1.5previously estimated $1.522 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 impacteffect 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.landowners. 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 2009, SWEPCo filed a motion to dismiss the appeal. In March 2009, the motion was granted.
In November 2008, SWEPCo received the required air permit approval from the Arkansas Department of Environmental Quality and commenced construction. In December 2008, Arkansas landowners filed an appeal with the Arkansas Pollution Control and Ecology Commission (APCEC) which caused construction of the Turk Plant to halt until the APCEC took further action. In December 2008, SWEPCo filed a request with the APCEC to continue construction of the Turk Plant and the APCEC ruled to allow construction to continue while an appeal of the Turk Plant’s permit is heard. Hearings on the air permit appeal are scheduled for June 2009. SWEPCo is also working with the U.S. Army Corps of Engineers for the approval of a wetlands and stream impact permit. In March 2009, SWEPCo reported to the U.S. Army Corps of Engineers a potential wetlands impact on approximately 2.5 acres at the Turk Plant. The U.S. Army Corps of Engineers directed SWEPCo to cease further work impacting the wetland areas. Construction has continued on other areas of the Turk Plant. The impact on the construction schedule and workforce is currently being evaluated by management.
In January 2008 and July 2008, SWEPCo filed Certificate of Environmental Compatibility and Public Need (CECPN) 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. TheIn June 2008, the landowner filed an appeal to the Arkansas State Court of Appeals in June 2008.requesting to re-litigate Turk Plant issues. SWEPCo responded and the appeal was dismissed. In January 2009, the APSC approved the CECPN applications.
The Arkansas Governor’s Commission on Global Warming is scheduled to issueissued its final report to the Governor by November 1,in October 2008. The Commission was established to set a global warming pollution reduction goal together with a strategic plan for implementation in Arkansas. The Commission’s final report included a recommendation that the Turk Plant employ post combustion carbon capture and storage measures as soon as it starts operating. If legislation is passed as a result of the findings in the Commission’s report, it could impact SWEPCo’s proposal to build and operate 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 paidcosts incurred plus related shutdown 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,March 31, 2009, SWEPCo has capitalized approximately $448$480 million of expenditures (including AFUDC) and has significant contractual construction commitments for an additional $771$655 million. As of September 30, 2008,March 31, 2009, if the plant had been cancelled, SWEPCo would have incurred cancellation fees of $61 million would have been required in order to terminate these construction commitments.$100 million. 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 MayApril 2008, the Virginia SCC denied APCo’s request to reconsider the Virginia SCC’s previous denial ofissued an order denying 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. Comments were filed by various parties, including APCo, but the WVPSC has not taken any action. 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,March 2009, APCo deferred for future recovery preconstruction IGCC costs of $19$20 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, neither CSPCo nor OPCo are engaged in a continuous course of construction on the IGCC plant. However, 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 1pre-construction 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.
PSO Purchase Power Agreement
PSO and Exelon Generation Company LLC, a subsidiary of Exelon Corporation, executed a long-term purchase power agreement (PPA) for which an application seeking its approval is expected to be filed with the OCC. The PPA is for the purchase of up to 520 MW of electric generation from the 795 MW natural gas-fired Green Country Generating Station, located in Jenks, Oklahoma. The agreement is the result of PSO’s 2008 Request for Proposals following a December 2007 OCC order that found PSO had a need for new baseload generation by 2012.
Environmental Matters
The Registrant Subsidiaries 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:
· | Requirements under the CAA to reduce emissions of SO2, NOx, PMparticulate matter (PM) and mercury from fossil fuel-fired power plants; and |
· | Requirements under the Clean Water Act (CWA) to reduce the impacts of water intake structures on aquatic species at certain power plants. |
In addition, the Registrant Subsidiaries 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 I&M’s nuclear units. Management is also engagedinvolved in the development of possible future requirements to reduce CO2 and other greenhouse gasgases (GHG) emissions to address concerns about global climate change. All of these matters are discussed in the “Environmental Matters” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 20072008 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. Management is 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. Management is 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 the AEP System’s facilities.
In anticipation of compliance with CAIR in 2009, I&M purchased $9 million of annual CAIR NOx allowances. The market value of annual CAIR NOx allowances decreased following this court decision. However, the 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 the other Registrant Subsidiaries purchased any significant number of CAIR allowances. SO2 and seasonal NOx allowances allocated to the Registrant Subsidiaries’ 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 the AEP System’s environmental compliance strategy. However, independent obligations under the CAA, including obligations under future state implementation plan submittals, and actions taken pursuant to the settlement of the NSR enforcement action, are consistent with the actions included in the AEP System’s least-cost CAIR compliance plan. Consequently, management does not anticipate making any immediate changes in the 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. Management plans 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 the AEP System’s 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. Management plans 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 the AEP System’s business. Permitting for a demonstration project at the Mountaineer Plant will proceed under the existing UIC rules.
Clean Water Act Regulation
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. Management expected additional capital and operating expenses, which the Federal EPA estimated could be $193 million for the AEP System’s plants. The Registrant Subsidiaries undertook site-specific studies and have been evaluating site-specific compliance or mitigation measures that could significantly change these cost estimates. The following table shows the investment amount per Registrant Subsidiary.
| Estimated | |
| Compliance | |
| Investments | |
Company | (in millions) | |
APCo | | $ | 21 | |
CSPCo | | | 19 | |
I&M | | | 118 | |
OPCo | | | 31 | |
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. Management cannot predict further action of the Federal EPA or what effect it may have on similar requirements adopted by the states. The Registrant Subsidiaries sought further review and filed for relief from the schedules included in their permits.
In April 2008,2009, the U.S. Supreme Court agreed to review decisions from the Second Circuit Court of Appealsissued a decision that limitallows the Federal EPA’s abilityEPA the discretion to weighrely on cost-benefit analysis in setting national performance standards and in providing for cost-benefit variances from those standards as part of the retrofittingregulations. Management cannot predict if or how the Federal EPA will apply this decision to any revision of the regulations or what effect it may have on similar requirements adopted by the states.
Potential Regulation of CO2 and Other GHG Emissions
As discussed in the 2008 Annual Report, CO2 and other GHG are alleged to contribute to climate change. In April 2009, the Federal EPA issued a proposed endangerment finding under the CAA regarding GHG emissions from motor vehicles. The proposed endangerment finding is subject to public comment. This finding could lead to regulation of CO2 and other gases under existing laws. Congress continues to discuss new legislation related to the control of these emissions. Some policy approaches being discussed would have significant and widespread negative consequences for the national economy and major U.S. industrial enterprises, including the AEP System. Because of these adverse consequences, management believes that these more extreme policies will not ultimately be adopted. Even if reasonable CO2 and other GHG emission standards are imposed, they will still require the Registrant Subsidiaries to make material expenditures. Management believes that costs against environmental benefits. Management is unable to predict the outcome of this appeal.complying with new CO2 and other GHG emission standards will be treated like all other reasonable costs of serving customers, and should be recoverable from customers as costs of doing business including capital investments with a return on investment.
Adoption of New Accounting Pronouncements
In September 2006, theThe FASB issued SFAS 157, enhancing existing guidance141R (revised “Business Combinations” 2007) improving financial reporting about business combinations and their effects. SFAS 141R can affect tax positions on previous acquisitions. The Registrant Subsidiaries do not have any such tax positions that result in adjustments. The Registrant Subsidiaries adopted SFAS 141R effective January 1, 2009. The Registrant Subsidiaries will apply it to any future business combinations.
The FASB issued SFAS 160 “Noncontrolling Interest in Consolidated Financial Statements” (SFAS 160), modifying reporting for fair value measurement of assets and liabilities and instruments measured at fair value that are classifiednoncontrolling interest (minority interest) in shareholders’ equity.consolidated financial statements. The statement defines fair value,requires noncontrolling interest be reported in equity and establishes a fair value measurementnew framework for recognizing net income or loss and expands fair value disclosures. It emphasizes that fair value is market-based withcomprehensive income by the highest measurement hierarchy level being market prices in active markets.controlling interest. The Registrant Subsidiaries adopted SFAS 160 retrospectively effective January 1, 2009. See Note 2.
The FASB issued SFAS 161 “Disclosures about Derivative Instruments and Hedging Activities” (SFAS 161), enhancing disclosure requirements for derivative instruments and hedging activities. The standard requires fair value measurementsthat objectives for using derivative instruments be disclosed by hierarchy level, an entity includes its own credit standing in the measurementterms of its liabilitiesunderlying risk and modifies the transaction price presumption.accounting designation. This standard increased disclosure requirements related to derivative instruments and hedging activities in future reports. The standard also nullifies the consensus reached inRegistrant Subsidiaries adopted SFAS 161 effective January 1, 2009.
The FASB ratified EITF Issue No. 02-3 “Issues Involved in08-5 “Issuer’s Accounting for Derivative Contracts Held for Trading PurposesLiabilities Measured at Fair Value with a Third-Party Credit Enhancement” (EITF 08-5) a consensus on liabilities with third-party credit enhancements when the liability is measured and Contracts Involveddisclosed at fair value. The consensus treats the liability and the credit enhancement as two units of accounting. The Registrant Subsidiaries adopted EITF 08-5 effective January 1, 2009. It will be applied prospectively with the effect of initial application included as a change 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 liability.
The FASB ratified EITF Issue No. 08-6 “Equity Method Investment Accounting Considerations” (EITF 08-6), a consensus on equity method investment accounting including initial and allocated carrying values and subsequent measurements. The Registrant Subsidiaries prospectively adopted EITF 08-6 effective January 1, 2009 with no impact on their financial statements.
The FASB issued FSP SFAS 157-1 “Application142-3 “Determination of FASB Statement No. 157the Useful Life of Intangible Assets” amending factors that should be considered in developing renewal or extension assumptions used to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposesdetermine the useful life of Lease Classification or Measurement under Statement 13” which amends SFAS 157a recognized intangible asset. The Registrant Subsidiaries adopted the rule effective January 1, 2009. The guidance is prospectively applied to exclude SFAS 13 “Accounting for Leases” and other accounting pronouncements that address fair value measurements for purposesintangible assets acquired after the effective date. The standard’s disclosure requirements are applied prospectively to all intangible assets as of lease classification or measurement under SFAS 13. In February 2008,January 1, 2009. The adoption of this standard had no impact on the financial statements.
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 FSPAs defined in SFAS 157-3 “Determining the Fair Value of 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. The Registrant Subsidiaries partially adopted SFAS 157 effective January 1, 2008. FSP SFAS 157-3 is effective upon issuance. The Registrant Subsidiaries will fully adopt SFAS 157 effective January 1, 2009 for items within the scope of FSP SFAS 157-2. Although the statement is applied prospectively upon adoption, in accordance with the provisions of SFAS 157 related to EITF 02-3, APCo, CSPCo and OPCo reduced beginning retained earnings by $440 thousand ($286 thousand, net of tax), $486 thousand ($316 thousand, net of tax) and $434 thousand ($282 thousand, net of tax), respectively, for the transition adjustment. SWEPCo’s transition adjustment was a favorable $16 thousand ($10 thousand, net of tax) adjustment to beginning retained earnings. The impact of considering AEP’s credit risk when measuring the fair value of liabilities, including derivatives, had an immaterial impact on fair value measurements upon adoption. See “SFAS 157 “Fair Value Measurements” (SFAS 157)” section of Note 2.
In February 2007, the FASB issued 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 asthe price that would be received to sell an asset or paid to transfer a cumulative effect adjustmentliability in an orderly transaction between market participants at the measurement date. The fair value hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities and the opening balancelowest priority to unobservable inputs. In the absence of retained earnings. The statementquoted prices for identical or similar assets or investments in active markets, fair value is applied prospectively upon adoption.estimated using various internal and external valuation methods including cash flow analysis and appraisals. The Registrant Subsidiaries adopted SFAS 159157-2 effective January 1, 2008. At adoption, the2009. The Registrant Subsidiaries will apply these requirements to applicable fair value measurements which include new asset retirement obligations and impairment analysis related to long-lived assets, equity investments, goodwill and intangibles. The Registrant Subsidiaries did not elect therecord any fair value optionmeasurements for any assets or liabilities.
In March 2007, the FASB ratified 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. The Registrant Subsidiaries adopted EITF 06-10 effective January 1, 2008. The impact of this standard was an unfavorable cumulative effect adjustment, net of tax, to beginning retained earnings as follows:
| | Retained | | | |
| | Earnings | | Tax | |
Company | | Reduction | | Amount | |
| | (in thousands) | |
APCo | | | $ | 2,181 | | | $ | 1,175 | |
CSPCo | | | | 1,095 | | | | 589 | |
I&M | | | | 1,398 | | | | 753 | |
OPCo | | | | 1,864 | | | | 1,004 | |
PSO | | | | 1,107 | | | | 596 | |
SWEPCo | | | | 1,156 | | | | 622 | |
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. The Registrant Subsidiaries 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 the Registrant Subsidiaries’ 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. The Registrant Subsidiaries adopted FIN 39-1 effective January 1, 2008. This standard changed the method of netting certain balance sheet amounts and reduced assets and liabilities. It requires retrospective application as a change in accounting principle. See “FSP FIN 39-1 “Amendment of FASB Interpretation No. 39” (FIN 39-1)” section of Note 2. Consequently, the Registrant Subsidiaries reduced totalnonrecurring nonfinancial assets and liabilities on their December 31, 2007 balance sheet as follows:in the first quarter of 2009.
Company | | (in thousands) | |
APCo | | $ | 7,646 | |
CSPCo | | | 4,423 | |
I&M | | | 4,251 | |
OPCo | | | 5,234 | |
PSO | | | 187 | |
SWEPCo | | | 229 | |