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, 2010March 31, 2011
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, StateRegistrants; States of Incorporation,Incorporation; | | I.R.S. Employer |
File Number | | Address of Principal Executive Offices, and Telephone Number | | Identification No.Nos. |
| | | | |
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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). |
Yes | X | | 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 have submitted electronically and posted on the AEP corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T 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 29, 20102011
|
| | | |
American Electric Power Company, Inc. | | | 480,276,270481,790,955 |
| | | ($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 TOOF QUARTERLY REPORTS ON FORM 10-Q
September 30, 2010March 31, 2011
| | Page |
Glossary of Terms | | i |
| | |
Forward-Looking Information | | iv |
| | |
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:Market Risk: | | |
American Electric Power Company, Inc. and Subsidiary Companies: | | |
| Management’s Financial Discussion and Analysis of Results of Operations | | 1 |
| Quantitative and Qualitative Disclosures About Market Risk Management Activities | | 2017 |
| Condensed Consolidated Financial Statements | | 2421 |
| Index toof Condensed Notes to Condensed Consolidated Financial Statements | | 2926 |
| | | |
Appalachian Power Company and Subsidiaries: | | |
| Management’s Financial Discussion and Analysis | | 8573 |
| Quantitative and Qualitative Disclosures About Market Risk Management Activities | | 90 |
| Condensed Consolidated Financial Statements | | 91 |
| Index toof Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries | | 96 |
| | | |
Columbus Southern Power Company and Subsidiaries: | | |
| Management’s Narrative Financial Discussion and Analysis | | 98 |
| Quantitative and Qualitative Disclosures About Market Risk Management Activities | | 102 |
| Condensed Consolidated Financial Statements | | 10391 |
| Index toof Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries | | 10896 |
| | | |
Indiana Michigan Power Company and Subsidiaries: | | |
| Management’s Narrative Financial Discussion and Analysis | | 11098 |
| Quantitative and Qualitative Disclosures About Market Risk Management Activities | | 114100 |
| Condensed Consolidated Financial Statements | | 115101 |
| Index toof Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries | | 120106 |
| | | |
Ohio Power Company Consolidated: | | |
| Management’s Financial Discussion and Analysis | | 122108 |
| Quantitative and Qualitative Disclosures About Market Risk Management Activities | | 128113 |
| Condensed Consolidated Financial Statements | | 129114 |
| Index toof Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries | | 134119 |
| | | |
Public Service Company of Oklahoma: | | |
| Management’s Financial Discussion and Analysis | | 136121 |
| Quantitative and Qualitative Disclosures About Market Risk Management Activities | | 140124 |
| Condensed Financial Statements | | 141125 |
| Index toof Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries | | 146130 |
| | | |
Southwestern Electric Power Company Consolidated: | | |
| Management’s Financial Discussion and Analysis | | 148132 |
| Quantitative and Qualitative Disclosures About Market Risk Management Activities | | 154 |
| Condensed Consolidated Financial Statements | | 155137 |
| Index toof Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries | | 160142 |
Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries | | 161143 |
| | | |
Combined Management’s Discussion and Analysis of Registrant Subsidiaries | | 230201 |
| | | |
Controls and Procedures | | 239211 |
| | | | |
Part II. OTHER INFORMATION | | |
| | |
| Item 1. | Legal Proceedings | | 240 |
| Item 1A. | Risk Factors | | 240212 |
| Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | | 244214 |
| Item 5. | Other Information | | 244214 |
| Item 6. | Exhibits: | | 244214 |
| | | | | Exhibit 12 | | |
| | | | | Exhibit 31(a) | | |
| | | | | Exhibit 31(b) | | |
| | | | | Exhibit 32(a) | | |
| | | | | Exhibit 32(b) | | |
| | | | | | | |
SIGNATURE | | | 245 |
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. |
GLOSSARY OF TERMS
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. |
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. |
AEP System or the 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. |
AEPEP | | AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, asset management and commercial and industrial sales in the deregulated Texas market. |
AEPSC | | American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries. |
AFUDC | | Allowance for Funds Used During Construction. |
AOCI | | Accumulated Other Comprehensive Income. |
APCo | | Appalachian Power Company, an AEP electric utility subsidiary. |
APSC | | Arkansas Public Service Commission. |
ASUBOA | | Accounting Standard Update.Bank of America Corporation. |
CAA | | Clean Air Act. |
CLECO | | Central Louisiana Electric Company, a nonaffiliated utility company. |
CO2 | | Carbon Dioxide and other greenhouse gases. |
Cook Plant | | Donald C. Cook Nuclear Plant, a two-unit, 2,191 MW nuclear plant owned by I&M. |
CSPCo | | Columbus Southern Power Company, an AEP electric utility subsidiary. |
CTC | | Competition Transition Charge. |
CWIP | | Construction Work in Progress. |
DCC Fuel | | DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel IIIII LLC, consolidated variable interest entities formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. |
DETM | | Duke Energy Trading and Marketing L.L.C., a risk management counterparty. |
DHLC | | Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo. |
E&R | | Environmental compliance and transmission and distribution system reliability. |
EIS | | Energy Insurance Services, Inc., a nonaffiliated captive insurance company. |
ERCOT | | Electric Reliability Council of Texas. |
ESP | | Electric Security Plans, filed with the PUCO, pursuant to the Ohio Amendments. |
ETT | | Electric Transmission Texas, LLC, an equity interest joint venture between AEP Utilities, Inc. and MidAmerican Energy Holdings Company Texas Transco, LLC formed to own and operate electric transmission facilities in ERCOT. |
FAC | | Fuel Adjustment Clause. |
FASB | | Financial Accounting Standards Board. |
Federal EPA | | United States Environmental Protection Agency. |
FERC | | Federal Energy Regulatory Commission. |
FGD | | Flue Gas Desulfurization or Scrubbers. |
Term | | Meaning |
| | |
FTR | | Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices. |
GAAP | | Accounting Principles Generally Accepted in the United States of America. |
I&M | | Indiana Michigan Power Company, an AEP electric utility subsidiary. |
Term | | Meaning |
| | |
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. |
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. |
MPSC | | Michigan Public Service Commission. |
MTM | | Mark-to-Market. |
MW | | Megawatt. |
MWH | | Megawatthour. |
NEIL | | Nuclear Electric Insurance Limited. |
NOx | | Nitrogen oxide. |
Nonutility Money Pool | | AEP’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. |
OVEC | | Ohio Valley Electric Corporation, which is 43.47% owned by AEP. |
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. |
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. |
RTO | | Regional Transmission Organization. |
Sabine | | Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity. |
Term | | Meaning |
| | |
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. |
SWEPCo | | Southwestern Electric Power Company, an AEP electric utility subsidiary. |
TCC | | AEP Texas Central Company, an AEP electric utility subsidiary. |
Texas Restructuring Legislation | | Legislation enacted in 1999 to restructure the electric utility industry in Texas. |
TNC | | AEP Texas North Company, an AEP electric utility subsidiary. |
Term | | Meaning |
| | |
Transition Funding | | AEP Texas Central Transition Funding I LLC and AEP Texas Central Transition Funding II LLC, wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for the purpose of issuing and servicing securitization bonds related to Texas restructuring law. |
True-up Proceeding | | A filing made under the Texas Restructuring Legislation to finalize the amount of stranded costs and other true-up items and the recovery of such amounts. |
Turk Plant | | John W. Turk, Jr. Plant. |
Utility Money Pool | | AEP System’s Utility Money Pool. |
VIE | | Variable Interest Entity. |
Virginia SCC | | Virginia State Corporation Commission. |
WPCo | | Wheeling Power Company, an AEP electric utility subsidiary. |
WVPSC | | Public Service Commission of West Virginia. |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
FORWARD-LOOKING INFORMATION
This report made by AEP and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEPMany forward-looking statements appear in “Item 7 – Management’s Financial Discussion and eachAnalysis” of its Registrant Subsidiaries believe that their expectationsthe 2010 Annual Report, but there are based on reasonable assumptions, any such statementsothers throughout this document which may be influencedidentified by factorswords such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflecting future results or guidance and statements of outlook. These matters are subject to risks and uncertainties that could cause actual outcomes and results to bediffer materially different from those projected. Forward-looking statements in this document speak only as of the date of this document. Except to the extent required by applicable law, we undertake no obligation to update or revise any forward-looking statement. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:
· | The economic climate 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, customer growth and the impact of retail competition, particularly in Ohio. |
· | Weather conditions, including storms, and our ability to recover significant storm restoration costs through applicable rate mechanisms. |
· | Available sources and costs of, and transportation for, fuels and the creditworthiness and performance of fuel suppliers and transporters. |
· | Availability of necessary generating capacity and the performance of our generating plants. |
· | Our ability to resolve I&M’s Donald C. Cook Nuclear Plant Unit 1 restoration and outage-related issues through warranty, insurance and the regulatory process. |
· | 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, including the Turk Plant, 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 oversight of energy commodity trading and new or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and other substances or additional regulation of fly ash and similar combustion products that could impact the continued operation and cost recovery of our plants. |
· | Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, (includingincluding rate or other recovery of new investments in generation, distribution and transmission service and environmental compliance).compliance. |
· | Resolution of litigation (including our dispute with Bank of America).litigation. |
· | Our ability to constrain operation and maintenance costs. |
· | Our ability to develop and execute a strategy based on a view regarding prices of electricity, 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 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 ESPs and related regulation in Ohio and the allocation of costs within 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, captive insurance entity and nuclear decommissioning trust and the impact on future funding requirements. |
· | Prices and demand for power that we generate and sell at wholesale. |
· | Changes in technology, particularly with respect to new, developing or alternative sources of generation. |
· | Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber security threats and other catastrophic events. |
· | Our ability to recover through rates or prices any remaining unrecovered investment in generating units that may be retired before the end of their previously projected useful lives. |
· | Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, including nuclear fuel. |
AEP 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
Economic Conditions
Retail margins increased during the first nine monthsquarter of 20102011 due to successful rate proceedings in our various jurisdictions and higher overall industrial usage partially offset by decreased residential and commercial demand for electricityusage primarily as a result of less favorable weatherweather. While lower in comparison to the first quarter of 2010, heating degree days were higher than normal throughout our service territories. In comparison to the recessionary lows of 2009,Our industrial sales increased 6%7% primarily due to increased production levels by Ormet, a large aluminum manufacturer in the third quarter and 5% during the first nine months of 2010.Ohio.
Regulatory Activity
Our significant 2010 rate proceedings include:Ohio 2009 – 2011 ESPs
Kentucky – In June 2010, a settlement was approved by the KPSC to increase annual base rates by $64 million based on a 10.5% return on common equity. New rates became effective with the first billing cycle of July 2010.
|
|
Michigan – In October 2010, a settlement was approved by the MPSC to increase annual base rates by $36 million based on a 10.35% return on common equity as well as the approval of certain surcharges. New rates will become effective with the first billing cycle of December 2010.
|
|
Oklahoma – In July 2010, PSO filed for an $82 million increase in annual base rates, including $30 million that is currently being recovered through a rider. The requested increase is based on an 11.5% return on common equity. Various parties’ net annual rate recommendations ranged from a rate reduction of $18 million to an increase of less than $1 million. A hearing is scheduled for December 2010.
|
|
Texas – In April 2010, a settlement was approved by the PUCT to increase SWEPCo’s base rates by approximately $15 million annually, effective May 2010, including a return on equity of 10.33%. The settlement agreement also allows SWEPCo a $10 million one-year surcharge rider to recover additional vegetation management costs that SWEPCo must spend within two years.
|
|
Virginia – In July 2010, the Virginia SCC authorized an annual increase in revenues of $62 million based on a 10.53% return on equity. The order disallowed recovery of $54 million of costs related to the Mountaineer Carbon Capture and Storage Project and allowed the deferral of approximately $25 million of incremental storm expenses incurred in 2009. As a result, APCo recorded a pretax loss of $29 million in the second quarter of 2010.
|
|
West Virginia – In May 2010, APCo and WPCo filed a request with the WVPSC to increase annual base rates by $156 million to be effective March 2011. The request is based on an 11.75% return on common equity and includes a request for recovery of and a return on the West Virginia jurisdictional share of the Mountaineer Carbon Capture and Storage Project. A decision from the WVPSC is expected in March 2011.
|
In April 2011, the Supreme Court of Ohio issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged resulting in three reversals, two of which may have a prospective impact. If any rate changes result from the PUCO’s remand proceedings, such rate changes would be prospective from the date of the remand order through the remainder of 2011. See “Ohio Electric Security Plan Filings” section of Note 2.
Ohio January 2012 – May 2014 ESP
In January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing for generation effective with the first billing cycle of January 2012 through the last billing cycle of May 2014. The SSO presents redesigned generation rates by customer class. Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013. Under the new ESP, management estimates CSPCo and OPCo will have base generation increases, excluding riders, of $17 million and $48 million, respectively, for 2012 and $46 million and $60 million, respectively, for 2013. The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESP could impact the outcome of the January 2012 – May 2014 ESP, though the nature and extent of that impact is not presently known. See “Ohio Electric Security Plan Filings” section of Note 2.
Ohio Distribution Base Rate Case
In February 2011, CSPCo and OPCo filed with the PUCO for an annual increase in distribution rates of $34 million and $60 million, respectively. The requested increase is based upon an 11.15% return on common equity to be effective January 2012. In addition to the annual increase, CSPCo and OPCo requested recovery of the projected December 31, 2012 balance of certain distribution regulatory assets of $216 million and $159 million, respectively, to be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013.
Virginia Regulatory Activity
In March 2011, APCo filed a generation and distribution base rate request with the Virginia SCC to increase annual base rates by $126 million based upon an 11.65% return on common equity to be effective no later than February 2012. The return on common equity includes a requested 0.5% renewable portfolio standards incentive as allowed by law. APCo proposed to mitigate the requested base rate increase by $51 million by maintaining current depreciation rates until the next biennial filing. If approved, APCo’s net base rate increase would be $75 million. See “Virginia Biennial Base Rate Case” section of Note 2.
West Virginia Regulatory Activity
In May 2010, APCo and WPCo filed a request with the WVPSC to increase annual base rates. In March 2011, the WVPSC modified and approved a settlement agreement which increased annual base rates by approximately $51 million based upon a 10% return on common equity. The order also resulted in a pretax write-off of a portion of the
Mountaineer Carbon Capture and Storage Product Validation Facility in the first quarter of 2011. See “Mountaineer Carbon Capture and Storage Project Product Validation Facility” section below. In addition, the WVPSC allowed APCo to defer and amortize $18 million of previously expensed 2009 incremental storm expenses and allowed APCo and WPCo to defer and amortize $15 million of costs that were previously expensed related to the 2010 cost reduction initiative, each over a period of seven years. See “2010 West Virginia Base Rate Case” section of Note 2.
Turk Plant
SWEPCo is currently constructing the Turk Plant, a new base load 600 MW coal generating unit in Arkansas, which is expected to be in service in 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility. SWEPCo’s share of construction costs is currently estimated to costbe $1.3 billion, excluding AFUDC, plus an additional $132$125 million for transmission, excluding AFUDC. The APSC, LPSC and PUCT approved SWEPCo’s original application to build the Turk Plant. In June 2010, the APSC issued an order which reversed and set aside the previously granted Certificate of Environmental Compatibility and Public Need. Various proceedings are pending that challenge the Turk Plant’s construction and its approved airwetlands and wetlandsair permits. In July 2010, the Arkansas Court of Appeals issued a decision remanding all transmission line Certificate of Environmental Compatibility and Public Need (CECPN) appeals to the APSC. As a result, a stay was not ordered and construction continues on the affected transmission lines.
In June 2010, the Arkansas Supreme Court denied motions for rehearing filed by the APSC and SWEPCo related to the reversal of the APSC’s earlier grant of a CECPN for SWEPCo’s 88 MW Arkansas portion of the Turk Plant. As a result, in June 2010, SWEPCo filed notice with the APSC of its intent to proceed with construction of the Turk Plant but that SWEPCo no longer intends to pursue a CECPN to seek recovery of its Arkansas portion of Turk Plant costs in Arkansas retail rates.
In July 2010, the Hempstead County Hunting Club filed a complaint with the Federal District Court for the Western District of Arkansas against SWEPCo, the U.S. Army Corps of Engineers, the U.S. Department of Interior and the U.S. Fish and Wildlife Service seeking an injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws. The Sierra Club, the Audubon Society and others filed a similar complaint in the same court. In October 2010, the motions for preliminary injunction were partially granted. According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop. Mitigation measures r equiredrequired by the permit are authorized and may be completed. The preliminary injunction affects portions of the water intake and associated piping and portions of thetwo transmission lines. In October 2010,A hearing on SWEPCo’s appeal was held in March 2011. Management is unable to predict the Federal District Court certified issues relating to the state law claims to the Arkansas Supreme Court, including whether those claims are within the primary jurisdictiontiming of the APSC. The Arkansas Supreme Court has yetoutcome related to consider the request. SWEPCo filed a notice of appeal with the Federal Court of Appeals for the Eighth Circuit and is seeking a stay of the preliminary injunction pending appeal.
this proceeding.
Management expects that SWEPCo will ultimately be able to complete construction of the Turk Plant and related transmission facilities and place those facilities in service. However, if SWEPCo is unable to complete the Turk Plant construction, including the related transmission facilities, and place the Turk Plant in service or if SWEPCo cannot recover all of its investment in and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition. See “Turk Plant” section of Note 2.
Ohio Customer Choice
In our Ohio service territory, various certifiedcompetitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service. As of September 30, 2010,Through March 31, 2011, approximately 2,0007,800 Ohio retail customers (primarily CSPCo customers) have switched to alternative CRES providers while approximately 1,200 additional Ohio customers have provided notice of their intent to switch.providers. As a result, in comparison to 2009,the first three months of 2010, we lost approximately $5$18 million of generation related gross margin through September 30, 2010 and currently forecast incremental lost margins of approximately $10 million and $53 million for the fourth quarter of 2010 and for all of 2011, respectively.March 31, 2011. We anticipate recovery of a portion of this lost margin through off-system sales. In addition, we havesales, including PJM capacity revenues, and our newly created our ownCRES provider. Our CRES provider t o targettargets retail customers in Ohio, both within and outside of our retail footprint.
Ohio Electric Security Plan Filings
During 2009, the PUCO issued an order that modified and approved CSPCo’s and OPCo’s ESPs which established rates through 2011. The order also limits annual rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011. The order provides a FAC for the three-year period of the ESP. Several notices of appeal are outstanding at the Supreme Court of Ohio relating to significant issues in the determination of the approved ESP rates. CSPCo and OPCo filed their 2009 significantly excessive earnings test with the PUCO. Based upon the methodology proposed by CSPCo and OPCo, neither CSPCo’s nor OPCo’s 2009 return on equity was significantly excessive. In October 2010, intervenors filed testimony wi th the PUCO recommending CSPCo return up to $156 million of its ESP revenues to customers. If the PUCO determines that CSPCo’s and/or OPCo’s 2009 return on equity was significantly excessive, CSPCo and/or OPCo may be required to return a portion of their ESP revenues to customers. See “Ohio Electric Security Plan Filings” section of Note 3.
Proposed CSPCo and OPCo Merger
In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo. Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company. The merger is also subject to regulatory approval by the FERC. CSPCo and OPCo anticipate completion of the merger during 2011. See “Proposed CSPCo and OPCo Merger” section of Note 3.service territory.
Cook Plant Unit 1 Fire and Shutdown
In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator. Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $395 million. Management believes that I&M should recover a significant portion of repair and replacement costs through the turbine vendor’s warranty, insurance and the regulatory process. I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power. The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors. As a result, theThe replacement of the repaired turbine rotors and other equipment is sch eduledscheduled for the Unit 1 planned outage in the fall of 2011. If the ultimate costs of the incident are not covered by warranty, insurance or through the related regulatory process or if any future regulatory proceedings are adverse, it could reduce future net income and cash flows and impact financial condition. See “Indiana Fuel Clause Filing”“Michigan 2009 and “Michigan 20092010 Power Supply Cost Recovery Reconciliation” sectionsReconciliations” section of Note 32 and “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.3.
As a result of the nuclear plant situation in Japan following an earthquake, we expect the Nuclear Regulatory Commission and possibly Congress to review safety procedures and requirements for nuclear generating facilities. This review could increase procedures and testing requirements and increase future operating costs at the Cook Plant.
Texas Restructuring Appeals
Pursuant to PUCT restructuring orders, TCC securitized net recoverable stranded generation costs of $2.5 billion and is recovering the principal and interest on the securitization bonds through the end of 2020. TCC also refunded other net true-up regulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider under PUCT restructuring orders. TCC and intervenors appealed the PUCT’s true-up related orders. After rulings from the Texas District Court and the Texas Court of Appeals, TCC, the PUCT and intervenors filed petitions for review with the Texas Supreme Court.Court of Texas. Review is discretionary and the Texas Supreme Court of Texas has not yet determined if it will grant review. See “Texas Restructuring Appeals” section of Note 3.2.
Mountaineer Carbon Capture and Storage Project
Product Validation Facility (PVF)
APCo and ALSTOM Power, Inc. (Alstom), an unrelated third party, jointly constructed a CO2 capture validation facility, which was placed into service in September 2009. APCo also constructed and owns the necessary facilities to store the CO2. In APCo’s July 2009 Virginia base rate filing and APCo’sWPCo’s May 2010 West Virginia base rate filing, APCo and WPCo requested recoveryrate base treatment of and a return on its Virginia and West Virginia jurisdictional share of its project costs andthe PVF, including recovery of the related asset retirement obligation regulatory asset amortization and accretion. In July 2010,March 2011, a WVPSC order denied the Virginia SCC issued arequest for rate base treatment of the PVF largely due to its experimental operation. The base rate order provided that denied recoveryshould APCo construct a commercial scale carbon capture and sequestration (CCS) facility, only the West Virginia portion of the Virginia sh are of the Mountaineer Carbon CapturePVF costs, based on load sharing among certain AEP operating companies, may be considered used and Storage Project costs, which resulteduseful plant in service and included in future rate base. As a result, APCo recorded a pretax write-off of approximately $54$41 million ($26 million net of tax) in the secondfirst quarter of 2010. Through September 30, 2010,2011. As of March 31, 2011, APCo has recorded a noncurrent regulatory asset of $59$19 million related to the Mountaineer Carbon Capture and Storage Project.PVF. If APCo cannot recover its remaining investmentsinvestment in and accretion expenses related to the Mountaineer Carbon Capture and Storage project,PVF, it would reduce future net income and cash flows and impact financial condition.flows. See “Mountaineer Carbon Capture and Storage Project” section of Note 3.2.
Capital ExpendituresCarbon Capture and Sequestration Project with the Department of Energy (DOE)
During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale CCS facility under consideration at the Mountaineer Plant. AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project. The DOE will fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million. A Front-End Engineering and Design (FEED) study, scheduled for completion during the third quarter of 2011, will refine the total cost estimate for the CCS facility. Results from the FEED study will be evaluated by management before any decision is made to seek the necessary regulatory approvals to build the CCS facility. As of March 31, 2011, APCo has incurred $25 million in total costs and has received $7 million of DOE eligible funding resulting in a net $18 million balance included in Construction Work In October 2010, we announced our capital expenditure budgetsProgress on the Condensed Consolidated Balance Sheets. Upon the completion of $2.6 billionthe FEED study and $2.9 billion for 2011the expected reimbursement of eligible cash expenditures, principally from the DOE, APCo expects a net investment of approximately $13 million. If APCo is unable to recover the costs of the CCS project, it would reduce future net income and 2012, respectively.cash flows. See “Mountaineer Carbon Capture and Storage Project” section of Note 2.
LITIGATION
In the ordinary course of business, we are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual resolution will be or the timing and amount of any loss, fine or penalty may be. We assess the probability of loss for each contingency and accrue a liability for cases that have a probable likelihood of loss if the loss can be estimated. For details on our regulatory proceedings and pending litigation see Note 4 – Rate Matters, Note 6 – Commitments, Guarantees and Contingencies and the “Litigation” section of “Management’s Financial Discussion and Analysis of Results of Operations”Analysis” in the 20092010 Annual Report. Additionally, see Note 32 – Rate Matters and Note 43 – Commitments, Guarantees and Contingencies included herein. Adverse results in these proceedings have the potential to materially affect our net income.
ENVIRONMENTAL ISSUES
We are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements. We will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants from fossil fuel-fired power plants, and new proposals governing the beneficial use and disposal of coal combustion products.products and proposed clean water rules.
We are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of our nuclear units. We are also engaged in the development of possible future requirements including the items discussed below and reductions of CO2 emissions to address concerns about global climate change. See a complete discussion of these matters in the “Environmental Matters”Issues” section of “Management’s Financial Discussion and Analysis of Results of Operations”Analysis” in the 20092010 Annual Report. We will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. We should be able to recover these expenditures through market prices in deregulated jurisdictions. If not, the costs of environmental compliance could adversely affect future net income, cash flows and possibly financial condition.
Update to Environmental Controls Impact on the Generating Fleet
The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System. We continue to evaluate the impact of these rules, project scope and technology available to achieve compliance. In the first quarter of 2011, we revised our cost estimates for complying with these rules. We currently estimate that the environmental investment to meet these requirements for our coal-fired generating facilities ranges from approximately $5.1 billion to $11.2 billion between 2012 and 2020. These amounts include investments to replace a portion of approximately 5,500 MWs of older coal generation units.
The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules. The cost estimates will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans or federal implementation plans that impose standards more stringent than the proposed rules, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on our units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.
Clean Air Act Transport Rule (Transport Rule)
In July 2010, the Federal EPA issued a proposed rule to replace the Clean Air Interstate Rule (CAIR) that would impose new and more stringent requirements to control SO2 and NOx emissions from fossil fuel-fired electric generating units in 31 states and the District of Columbia. Each state covered by the Transport Rule is assigned an allowance budget for SO2 and/or NOx. Limited interstate trading is allowed on a sub-regional basis and intrastate trading is allowed among generating units. Certain of our western states (Texas, Arkansas and Oklahoma) would be subject to only the seasonal NOx program, with new limits that are proposed to take effect in 2012. The remainder of the states in which we operate would be subject to seasonal and annual NOx programs and an annual SO2 emissions reduction program that takes effect in two phases. The first phase becomes effective in 2012 and requires approximately 1one million tons per year more SO2 emission reductions across the region than would have been required under CAIR. The second phase takes effect in 2014 and reduces SO2 emissions by an additional 800,000 tons per year. The SO2and NOx programs rely on newly-created allowances rather than relying on the CAIR NOx allowances or the Title IV Acid Rain Program allowances used in the CAIR rule.CAIR. The time frames for and the extentstringency of the additional emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and our electric utility customers, as these requirements could accelerate unit retirements, increase capital requirements, constrain operations, decrease reliability and unfavorably impact financial condition if the increased costs are suspended during the early development stages not recovered in rates or market prices. CommentsThe Federal EPA requested comments on a scheme based exclusively on intrastate trading of allowances or a scheme that establishes unit-by-unit emission rates. Either of these options would provide less flexibility and exacerbate the proposed rule were due on October 1, 2010. Our comments pointed out the inaccuracies of somenegative impact of the assumptions used by the Federal EPA, the flawed nature of its modeling analysis and unreasonable time frame for implementing the rule. We believe that the Federal EPA made erroneous assumptions about the existence and/or capabilities of current control equipment at certain of our units, used timeframes for installation of new controls that are inconsistent with our recent experience and made questionable assumptions regarding the ability to switch fuel supplies at existing units. A notice of additional information was issued and comments on that package were accepted until October 15, 2010. The proposal indicates that the requirements are expected to be finalized in June 2011 and become effective January 1, 2012.
Mercury and Other Hazardous Air Pollutants (HAPs) Regulation
The Federal EPA issued the Clean Air Mercury Rule (CAMR) in 2005, setting mercury emission standards for new coal-fired power plants and requiring all states to issue new state implementation plans including mercury requirements for existing coal-fired power plants. The CAMR was vacated and remanded to the Federal EPA by the D.C. Circuit Court of Appeals in 2008. The Federal EPA issued an information collection request to owners and operators of existing power plants in 2010 to collect information to support the development of a maximum achievable control technology (MACT) standard for mercury and other hazardous air pollutant emissions under the CAA. Under the terms of a consent decree,In response, the Federal EPA is required to issue final MACT standards forhas been developing a rule addressing a broad range of hazardous air pollutants from coal and oil-fired power plants by November 2011. 0;plants. The Federal EPA Administrator signed a proposed HAPs rule in March 2011, but the rule has substantial discretionnot yet been published in determining howthe Federal Register. The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrochloric acid (as a surrogate for acid gases) for units burning coal and oil, on a site-wide 30-day rolling average basis. In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans. Compliance is required within three years of the effective date of the final rule, which is expected by November 2011 per the Federal EPA’s settlement agreement with several environmental groups. A one-year extension may be available if the extension is necessary for the installation of controls. We are developing comments to structuresubmit to the MACT standards. agency and collecting additional information regarding the performance of our coal-fired units. Comments will be accepted for 60 days after the rule is published in the Federal Register.
We will urge the Federal EPA to carefully consider all of the options available so that costly and inefficient control requirements are not imposed regardless of unit size, age or other operating characteristics. However, weWe have approximately 5,0005,500 MW of older coal units including 2,000 MW of older coal-fired capacity already subject to control requirements under the NSR consent decree, for which it may be economically inefficient to install scrubbers or other environmental controls.
Regional Haze
In March 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze state implementation plan (SIP) submitted by the State of Oklahoma through the Department of Environmental Quality. The timing and ultimate disposition of those units will be affected by: a) the MACT standards and other environmental regulations, b) the economics of maintaining the units, c) demand for electricity, d) availability and cost of replacement power and e) regulatory decisions about cost recoveryFederal EPA is proposing to approve all of the remaining investmentNOx control measures in those units.the SIP and disapprove the SO2 control measures for six electric generating units, including two units owned by PSO. The Federal EPA is proposing a federal implementation plan (FIP) that would require these units to install technology capable of reducing SO2 emissions to 0.06 pounds per million British thermal unit within three years of the effective date of the FIP. The proposal is open for public comment.
Coal Combustion Residual Rule
In June 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at our coal-fired electric generating units. The rule contains two alternative proposals, one that would impose federal hazardous waste disposal and management standards on these materials and one that would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management. Both proposals would impose stringent requirements for the construction of new coal ash landfills and would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and init iateinitiate closure within five years of the issuance of a final rule.
Currently, approximately 40% of the coal ash and other residual products from our generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses. Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes. In addition, we currently use surface impoundments and landfills to manage these materials at our generating facilities and will incur significant costs to upgrade or close and replace these existing facilities. We estimate that the potential compliance costs associated with the proposed solid waste management alternative could be as high as a total of $3.9 billion including AFUDC for un itsunits across the AEP System. Regulation of these materials as hazardous wastes would significantly increase these costs.
Clean Water Act Regulations
In March 2011, the Federal EPA Administrator signed a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against the plant’s cooling water intake screen (impingement) or entrained in the cooling water. Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress. The proposed standards affect all plants withdrawing more than two million gallons of cooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement. Compliance with this standard is required within eight years of the effective date of the final rule. The proposed standard for entrainment requires closed cycle cooling or a site-specific evaluation of the available measures for reducing entrainment. Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority. We will seek recoveryare evaluating the proposal and engaged in the collection of expenditures for pollution control technologies and associated costs from customers throughadditional information regarding the feasibility of implementing this proposal at our regulated rates (in regulated jurisdictions). We should be able to recover these expenditures through market pricesfacilities. Comments on the proposal are due within 90 days after the rule is published in deregulated jurisdictions. If not, these costs could adversely affect future net income, cash flows and possibly financial condition.the Federal Register.
Global Warming
While comprehensive economy-wide regulation of CO2 emissions might be mandated through new legislation, Congress has yet to enact such legislation. The Federal EPA continues to take action to regulate CO2 emissions under the existing requirements of the CAA. The Federal EPA issued a final endangerment finding for CO2 emissions from new motor vehicles in December 2009 and final rules for new motor vehicles in May 2010. The Federal EPA determined that CO2 emissions from stationary sources will be subject to regul ationregulation under the CAA beginning in January 2011 at the earliest and finalized its proposed scheme to streamline and phase-inphase in regulation of stationary source CO2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs. Theseprograms through the issuance of final federal rules, have been challenged in the courts.state implementation plan calls and federal implementation plans. The Federal EPA is reconsidering whether to include CO2 emissions in a number of stationary source standards, including standards that apply to new and modified electric utility units.units and announced a settlement agreement to issue proposed new source performance standards for utility boilers that would be applicable for both new and existing utility boilers. It is not possible at this time to estimate the costs of compliance with these new standards, but they may be material.
Our fossil fuel-fired generating units are very large sources of CO2 emissions. If substantial CO2 emission reductions are required, there will be significant increases in capital expenditures and operating costs which would impact the ultimate retirement of older, less-efficient, coal-fired units. To the extent we install additional controls on our generating plants to limit CO2 emissions and receive regulatory approvals to increase our rates, cost recovery could have a positive effect on future earnings. Prudently incurred capital investments made by our subsidiaries in rate-regula tedrate-regulated jurisdictions to comply with legal requirements and benefit customers are generally included in rate base for recovery and earn a return on investment. We would expect these principles to apply to investments made to address new environmental requirements. However, requests for rate increases reflecting these costs can affect us adversely because our regulators could limit the amount or timing of increased costs that we would recover through higher rates. In addition, to the extent our costs are relatively higher than our competitors’ costs, such as operators of nuclear and natural gas based generation, it could reduce our off-system sales or cause us to lose customers in jurisdictions that permit customers to choose their supplier of generation service.
Several states have adopted programs that directly regulate CO2 emissions from power plants, but none of these programs are currently in effect in states where we have generating facilities. Certain states, including Ohio, Michigan, Texas and Virginia, passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements. We are taking steps to comply with these requirements.
Certain groups have filed lawsuits alleging that emissions of CO2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others. We have been named in pending lawsuits, which we are vigorously defending. It is not possible to predict the outcome of these lawsuits or their impact on our operations or financial condition. See “Carbon Dioxide Public Nuisance Claims” and “Alaskan Villages’ Claims” sections of Note 4.3.
Future federal and state legislation or regulations that mandate limits on the emission of CO2 would result in significant increases in capital expenditures and operating costs, which in turn, could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force our utility subsidiaries to close some coal-fired facilities and could lead to possible impairment of assets. As a result, mandatory limits could have a material adverse impact on our net income, cash flows and financial condition.
For detailed information on global warming and the actions we are taking to address potential impacts, see Part I of the 20092010 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters – Global Warming” and “Management’s Financial Discussion and Analysis of Results of Operations.Analysis.”
RESULTS OF OPERATIONS
SEGMENTS
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 transport coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers. |
Generation and Marketing
| · | Wind farms and marketing and risk management activities primarily in ERCOT.ERCOT and to a lesser extent Ohio in PJM and MISO. |
The table below presents our consolidated Net Income (Loss) Before Extraordinary Loss by segment for the three and nine months ended September 30, 2010March 31, 2011 and 2009.2010.
| Three Months Ended September 30, | | Nine Months Ended September 30, | | | Three Months Ended March 31, |
| 2010 | | 2009 | | 2010 | | 2009 | | | 2011 | | 2010 |
| (in millions) | | | (in millions) |
Utility Operations | | $ | 541 | | | $ | 448 | | | $ | 1,017 | | | $ | 1,121 | | Utility Operations | $ | 378 | | $ | 344 |
AEP River Operations | | | 14 | | | | 10 | | | | 16 | | | | 22 | | AEP River Operations | | 7 | | 3 |
Generation and Marketing | | | - | | | | 5 | | | | 17 | | | | 33 | | Generation and Marketing | | 1 | | 10 |
All Other (a) | | | 2 | | | | (17 | ) | | | (10 | ) | | | (45 | ) | All Other (a) | | (31) | | | (11) |
Income Before Extraordinary Loss | | $ | 557 | | | $ | 446 | | | $ | 1,040 | | | $ | 1,131 | | |
Net Income | | Net Income | $ | 355 | | $ | 346 |
(a) | 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 settle and completely expire in the fourth quarter of 2011. |
| · | Revenue sharing related to the Plaquemine Cogeneration Facility.Facility which ends in the fourth quarter of 2011. |
AEP CONSOLIDATED
Third Quarter of 2010 Compared to Third Quarter of 2009
Income Before Extraordinary Loss in 2010 increased $111 million compared to 2009 primarily due to successful rate proceedings in our various jurisdictions and favorable weather throughout our service territory.
Average basic shares outstanding increased to 480 million in 2010 from 477 million in 2009.
Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009
Income Before Extraordinary Loss in 2010 decreased $91 million compared to 2009 primarily due to $182 million of charges incurred (net of tax) related to the cost reduction initiatives partially offset by successful rate proceedings in our various jurisdictions and favorable weather conditions throughout our service territory.
Average basic shares outstanding increased to 479 million in 2010 from 452 million in 2009 primarily due to the April 2009 issuance of 69 million shares of AEP common stock. Actual shares outstanding were 480 million as of September 30, 2010.
Our results of operations are discussed below by operating segment.
AEP CONSOLIDATED
First Quarter of 2011 Compared to First Quarter of 2010
Net Income increased from $346 million in 2010 to $355 million in 2011 primarily due to the following:
Ÿ | Successful rate proceedings in our various jurisdictions. |
Ÿ | The first quarter 2011 deferral of 2010 costs related to storms and cost reduction initiatives as approved in our March 2011 West Virginia base rate settlement. |
Ÿ | The unfavorable 2010 tax treatment associated with future reimbursement of Medicare Part D prescription drug benefits. |
|
These increases were partially offset by: |
|
Ÿ | A net loss incurred as a result of the February 2011 settlement of litigation with BOA and Enron. |
Ÿ | The write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied by the WVPSC in March 2011. |
Ÿ | The less favorable weather impact across our service territory in comparison to the first quarter of 2010. |
Average basic shares outstanding increased to 481 million in 2011 from 478 million in 2010. Actual shares outstanding were 482 million as of March 31, 2011.
Our results of operations are discussed below by operating segment.
UTILITY 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 operatingtotal revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances and purchased power.
| | Three Months Ended | | | Nine Months Ended | |
| | September 30, | | | September 30, | |
| | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| | (in millions) | |
Revenues | | $ | 3,907 | | | $ | 3,389 | | | $ | 10,544 | | | $ | 9,712 | |
Fuel and Purchased Power | | | 1,427 | | | | 1,145 | | | | 3,784 | | | | 3,337 | |
Gross Margin | | | 2,480 | | | | 2,244 | | | | 6,760 | | | | 6,375 | |
Depreciation and Amortization | | | 413 | | | | 412 | | | | 1,205 | | | | 1,173 | |
Other Operating Expenses | | | 1,057 | | | | 988 | | | | 3,411 | | | | 2,975 | |
Operating Income | | | 1,010 | | | | 844 | | | | 2,144 | | | | 2,227 | |
Other Income, Net | | | 39 | | | | 42 | | | | 124 | | | | 97 | |
Interest Expense | | | 238 | | | | 232 | | | | 710 | | | | 679 | |
Income Tax Expense | | | 270 | | | | 206 | | | | 541 | | | | 524 | |
Income Before Extraordinary Loss | | $ | 541 | | | $ | 448 | | | $ | 1,017 | | | $ | 1,121 | |
Summary of KWH Energy Sales for Utility Operations |
For the Three and Nine Months Ended September 30, 2010 and 2009 |
| | | | | | | | |
| | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
Energy/Delivery Summary | | 2010 | | 2009 | | 2010 | | 2009 |
| | (in millions of KWH) |
Retail: | | | | | | | | |
Residential | | 17,817 | | 15,968 | | 48,250 | | 44,730 |
Commercial | | 14,032 | | 13,569 | | 38,508 | | 37,773 |
Industrial | | 14,460 | | 13,642 | | 42,503 | | 40,563 |
Miscellaneous | | 832 | | 798 | | 2,328 | | 2,291 |
Total Retail (a) | | 47,141 | | 43,977 | | 131,589 | | 125,357 |
| | | | | | | | |
Wholesale | | 10,689 | | 8,285 | | 25,846 | | 22,229 |
| | | | | | | | |
Total KWHs | | 57,830 | | 52,262 | | 157,435 | | 147,586 |
| | | | | | | | |
(a) Includes energy delivered to customers served by AEP's Texas Wires Companies. |
| | Three Months Ended |
| | March 31, |
| | 2011 | | 2010 |
| | (in millions) |
Total Revenues | $ | 3,524 | | $ | 3,426 |
Fuel and Purchased Power | | 1,297 | | | 1,247 |
Gross Margin | | 2,227 | | | 2,179 |
Depreciation and Amortization | | 393 | | | 398 |
Other Operating Expenses | | 1,060 | | | 1,040 |
Operating Income | | 774 | | | 741 |
Other Income, Net | | 43 | | | 43 |
Interest Expense | | 232 | | | 235 |
Income Tax Expense | | 207 | | | 205 |
Net Income | $ | 378 | | $ | 344 |
Summary of KWH Energy Sales for Utility Operations |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in millions of KWH) |
Retail: | | | | | |
| Residential | | 16,949 | | | 17,774 |
| Commercial | | 11,646 | | | 11,475 |
| Industrial | | 14,329 | | | 13,381 |
| Miscellaneous | | 723 | | | 713 |
Total Retail (a) | | 43,647 | | | 43,343 |
| | | | | |
Wholesale | | 9,151 | | | 8,137 |
| | | | | |
Total KWHs | | 52,798 | | | 51,480 |
| | | | | | |
(a) Includes energy delivered to customers served by AEP's Texas Wires Companies. |
Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on net income. In general, degree day changes in our eastern region have a larger effect on net income than changes in our western region due to the relative size of the two regions and the number of customers within each region.
Summary of Heating and Cooling Degree Days for Utility Operations | For the Three and Nine Months Ended September 30, 2010 and 2009 | |
| | | | | | | | | | |
| | Three Months Ended | | Nine Months Ended | | Three Months Ended March 31, |
| | September 30, | September 30, | | 2011 | | 2010 |
| | 2010 | | 2009 | | 2010 | | 2009 | | (in degree days) |
| | (in degree days) | | | | | |
Eastern Region | Eastern Region | | | | | | | | | Eastern Region | | | | |
Actual - Heating (a) | Actual - Heating (a) | | 1 | | 6 | | 1,976 | | 1,982 | Actual - Heating (a) | | 1,854 | | 1,900 |
Normal - Heating (b) | Normal - Heating (b) | | 7 | | 7 | | 1,918 | | 1,969 | Normal - Heating (b) | | 1,739 | | 1,741 |
| | | | | | | | | | | | | | |
Actual - Cooling (c) | Actual - Cooling (c) | | 859 | | 509 | | 1,294 | | 813 | Actual - Cooling (c) | | 3 | | - |
Normal - Cooling (b) | Normal - Cooling (b) | | 691 | | 703 | | 984 | | 993 | Normal - Cooling (b) | | 3 | | 3 |
| | | | | | | | | | | | | | |
Western Region | Western Region | | | | | | | | | Western Region | | | | |
Actual - Heating (a) | Actual - Heating (a) | | - | | - | | 764 | | 540 | Actual - Heating (a) | | 692 | | 759 |
Normal - Heating (b) | Normal - Heating (b) | | 1 | | 1 | | 596 | | 601 | Normal - Heating (b) | | 579 | | 574 |
| | | | | | | | | | | | | | |
Actual - Cooling (d) | Actual - Cooling (d) | | 1,471 | | 1,349 | | 2,357 | | 2,309 | Actual - Cooling (d) | | 109 | | 20 |
Normal - Cooling (b) | Normal - Cooling (b) | | 1,353 | | 1,362 | | 2,168 | | 2,174 | Normal - Cooling (b) | | 58 | | 58 |
| | | | | | | | | | | | | | |
(a) | Eastern Region and Western Region heating degree days are calculated on a 55 degree temperature base. | 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. | Normal Heating/Cooling represents the thirty-year average of degree days. |
(c) | Eastern Region cooling degree days are calculated on a 65 degree temperature base. | Eastern Region cooling degree days are calculated on a 65 degree temperature base. |
(d) | Western Region cooling degree days are calculated on a 65 degree temperature base for PSO/SWEPCo and a 70 degree temperature base for TCC/TNC. | Western Region cooling degree days are calculated on a 65 degree temperature base for |
| | PSO/SWEPCO and a 70 degree temperature base for TCC/TNC. |
First Quarter of 2011 Compared to First Quarter of 2010 |
Third Quarter of 2010 Compared to Third Quarter of 2009 | | |
| | | | | | |
Reconciliation of Third Quarter of 2009 to Third Quarter of 2010 | | |
Income from Utility Operations Before Extraordinary Loss | | |
Reconciliation of First Quarter of 2010 to First Quarter of 2011 | | Reconciliation of First Quarter of 2010 to First Quarter of 2011 | |
Net Income from Utility Operations | | Net Income from Utility Operations | |
(in millions) | (in millions) | | (in millions) | |
| | | | | | |
Third Quarter of 2009 | | $ | 448 | | |
First Quarter of 2010 | | | $ | 344 | |
| | | | | | | | |
Changes in Gross Margin: | | | | | | | | |
Retail Margins | | | 246 | | | | 26 | |
Off-system Sales | | | 42 | | | | 12 | |
Transmission Revenues | | | | 8 | |
Other Revenues | | | (52 | ) | | | 2 | |
Total Change in Gross Margin | | | 236 | | | | 48 | |
| | | | | | | | |
Total Expenses and Other: | | | | | | | | |
Other Operation and Maintenance | | | (52 | ) | | | (14 | ) |
Depreciation and Amortization | | | (1 | ) | | | 5 | |
Taxes Other Than Income Taxes | | | (17 | ) | | | (6 | ) |
Interest and Investment Income | | | (4 | ) | |
Carrying Costs Income | | | 6 | | | | 1 | |
Allowance for Equity Funds Used During Construction | | | (6 | ) | | | (4 | ) |
Interest Expense | | | (6 | ) | | | 3 | |
Equity Earnings of Unconsolidated Subsidiaries | | | 1 | | | | 3 | |
Total Expenses and Other | | | (79 | ) | | | (12 | ) |
| | | | | | | | |
Income Tax Expense | | | (64 | ) | | | (2 | ) |
| | | | | | | | |
Third Quarter of 2010 | | $ | 541 | | |
First Quarter of 2011 | | | $ | 378 | |
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 $246$26 million primarily due to the following: |
| · | Successful rate proceedings in our service territories which include: |
| | · | A $31$35 million rate increase in the recovery of E&R costs in Virginia, construction financing costs in West Virginia and costs related to the Transmission Rate Adjustment Clause in Virginia.Ohio. |
| | · | A $22An $18 million rate increase in Kentucky. |
| | · | An $18A $13 million net rate increase for SWEPCo. |
| | · | A $16$10 million net rate increase for I&M. |
| | · | A $15 million rate increase in Oklahoma. |
| | · | A $13$5 million increase in the recovery of advanced metering costs in Texas. |
| | · | A $9 million net ratemargins from industrial sales partially due to an increase in our other jurisdictions. |
| | · | For the increases described above, $50 million of these rate increases relate to riders/trackers which have corresponding increasesproduction at Ormet, a major industrial customer in Other Operation and Maintenance expense line items discussed below. |
| · | A $131 million increase in weather-related usage primarily due to a 69% increase in cooling degree days in our eastern region. |
| · | A $19 million increase in fuel margins due to higher fuel and purchased power costs recorded in 2009 related to the Cook Plant Unit 1 (Unit 1) shutdown. This increase in fuel margins was offset by a corresponding decrease in Other Revenues as discussed below.Ohio. |
| These increases were partially offset by: |
| · | A $24$23 million net decrease in rate related margins for APCo primarily due to a favorable fuelthe expiration of E&R cost recovery adjustment in Ohio that was recordedVirginia and the implementation of higher interim rates in 2009.Virginia in January and February 2010. |
| · | A $9$20 million decrease in weather-related usage primarily due to the termination of an I&M unit power agreement.2% and 9% decreases in heating degree days in our eastern and western service territories, respectively. |
| · | An $18 million decrease attributable to CSPCo customers switching to alternative competitive retail electric service (CRES) providers. |
· | Margins from Off-system Sales increased $42$12 million primarily due to increased prices and higher physical sales volumesan increase in our eastern region,PJM capacity revenues, partially offset by lower trading and marketing margins. |
· | OtherTransmission Revenues decreased $52increased $8 million primarily due to the Cook Plant accidental outage insurance proceeds of $46 million which ended when Unit 1 returned to service in December 2009. I&M reduced customer bills by approximately $19 millionincreased revenues in the third quarter of 2009 for the cost of replacement power resulting from the Unit 1 outage. This decrease in insurance proceeds was offset by a corresponding increase in Retail Margins as discussed above.PJM region.
|
Total Expenses and Other and Income Taxes changed between years as follows:
· | Other Operation and Maintenance expenses increased $52$14 million primarily due to: |
| · | A $45$41 million increase due to the write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC in March 2011. |
| · | A $31 million increase in demand side management, energy efficiency, vegetation management programs and other related expenses. All of these expenses are currently recovered dollar-for-dollar in rate recovery riders/trackers in Gross Margin. |
| · | A $7$9 million increase in plant outage and other plant operating and maintenance expenses. |
| These increases were partially offset by: |
| · | A $33 million decrease due to the deferral of 2010 costs related to storms and our cost reduction initiative. These costs were deferred as a result of the approved modified settlement agreement in our West Virginia base rate case in March 2011. |
| · | A $20 million decrease in administrative and general expenses primarily due to a net increasedecrease in employee related expenses.fringe benefits. |
| · | A $13 million gain on the sale of land. |
· | Depreciation and Amortization expenses decreased $5 million primarily due to the expiration of E&R amortization of deferred carrying costs in Virginia offset by increased depreciation resulting from environmental upgrades at APCo. |
· | Taxes Other Than Income Taxes increased $17 million primarily due to increased revenue taxes as the result of higher than anticipated generation load and higher property taxes. |
· | Carrying Costs Income increased $6 million primarily due to increased environmental construction deferralshigher property taxes in Virginia and a higher under-recovered fuel balance for OPCo.Ohio.
|
· | Allowance for Equity Funds Used During Construction decreased $6$4 million primarily due to SWEPCo’s completed construction of the Stall Unit in June 2010. |
· | Interest Expense increased $6 million primarily due to an increase in long-term debt.
|
· | Income Tax Expense increased $64$2 million primarily due to an increase in pretax book income and other book/tax differences which are accounted for on a flow-through basis. |
Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009 |
| | | | |
Reconciliation of Nine Months Ended September 30, 2009 to Nine Months Ended September 30, 2010 |
Income from Utility Operations Before Extraordinary Loss |
(in millions) |
| | | | |
Nine Months Ended September 30, 2009 | | $ | 1,121 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins | | | 526 | |
Off-system Sales | | | 43 | |
Transmission Revenues | | | 8 | |
Other Revenues | | | (192) | |
Total Change in Gross Margin | | | 385 | |
| | | | |
Total Expensesbasis and Other: | | | | |
Other Operation and Maintenance | | | (396) | |
Depreciation and Amortization | | | (32) | |
Taxes Other Than Income Taxes | | | (40) | |
Interest and Investment Income | | | 4 | |
Carrying Costs Income | | | 18 | |
Allowance for Equity Funds Used During Construction | | | 1 | |
Interest Expense | | | (31) | |
Equity Earnings of Unconsolidated Subsidiaries | | | 4 | |
Total Expenses and Other | | | (472) | |
| | | | |
Income Tax Expense | | | (17) | |
| | | | |
Nine Months Ended September 30, 2010 | | $ | 1,017 | |
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 $526 million primarily due to the following:
|
| · | Successful rate proceedings in our service territories which include: |
| | · | A $106 million increase in the recovery of E&R costs in Virginia, construction financing costs in West Virginia and costs related to the Transmission Rate Adjustment Clause in Virginia. |
| | · | A $38 million increase in the recovery of advanced metering costs in Texas. |
| | · | A $34 million rate increase in Oklahoma. |
| | · | A $31 million net increase in rates for SWEPCo. |
| | · | A $26 million rate increase in Kentucky. |
| | · | A $25 million rate increase in Ohio. |
| | · | A $24 million net rate increase for I&M. |
| | · | A $6 million net increase in rates in our other jurisdictions. |
| | · | For the increases described above, $115 million of these rate increases relate to riders/trackers which have corresponding increases in Other Operation and Maintenance expense line items discussed below. |
| · | A $202 million increase in weather-related usage primarily due to a 59% increase in cooling degree days in our eastern region and a 41% increase in heating degree days in our western region. |
| · | A $59 million increase in fuel margins due to higher fuel and purchased power costs recorded in 2009 related to the Unit 1 shutdown. This increase in fuel margins was offset by a corresponding decrease in Other Revenues as discussed below. |
| These increases were partially offset by: |
| · | A $27 million decrease due to the termination of an I&M unit power agreement. |
· | Margins from Off-system Sales increased $43 million primarily due to increased prices and higher physical sales volumes in our eastern region, partially offset by lower trading and marketing margins.
|
· | Transmission Revenues increased $8 million primarily due to increased revenues in the ERCOT, PJM and SPP regions.
|
· | Other Revenues decreased $192 million primarily due to the Cook Plant accidental outage insurance proceeds of $145 million which ended when Unit 1 returned to service in December 2009. I&M reduced customer bills by approximately $59 million in the first nine months of 2009 for the cost of replacement power resulting from the Unit 1 outage. This decrease in insurance proceeds was offset by a corresponding increase in Retail Margins as discussed above. Other Revenues also decreased due to lower gains on sales of emission allowances of $26 million, partially offset by sharing in certain fuel clauses.
|
Total Expenses and Other and Income Taxes changed between years as follows:
· | Other Operation and Maintenance expenses increased $396 million primarily due to the following:
|
| · | A $275 million increase due to expenses related to cost reduction initiatives. |
| · | A $101 million increase in demand side management, energy efficiency, vegetation management programs and other related expenses. All of these expenses are currently recovered dollar-for-dollar in rate recovery riders/trackers in Gross Margin. |
| · | A $54 million increase due to the write-off of APCo’s Virginia Share of the Mountaineer Carbon Capture and Storage Project as denied for recovery by the Virginia SCC. |
| · | A $33 million increase primarily due to a net increase in employee related expenses. |
| These increases were partially offset by: |
| · | A $47 million decrease in storm related expenses primarily due to the deferral of $29 million of 2009 storm costs in Virginia as allowed by the Virginia SCC. |
| · | A $20 million decrease in customer assistance and other customer accounts expense. |
· | Depreciation and Amortization increased $32 million primarily due to new environmental control improvements placed in service at APCo, CSPCo and OPCo.
|
· | Taxes Other Than Income Taxes increased $40 million primarily due to increased revenue taxes as the result of higher than anticipated generation load, higher property and franchise taxes and the employer portion of payroll taxes incurred related to the cost reduction initiatives.
|
· | Carrying Costs Income increased $18 million primarily due to increased environmental construction deferrals in Virginia and a higher under-recovered fuel balance for OPCo.
|
· | Interest Expense increased $31 million primarily due to an increase in long-term debt and a decrease in the debt component of AFUDC due to lower CWIP balances at APCo, CSPCo and OPCo.
|
· | Income Tax Expense increased $17 million primarily due to the regulatory accounting treatment of state income taxes, other book/tax differences which are accounted for on a flow-through basis andpartially offset by the 2010 tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits, partially offset by a decrease in pretax book income.benefits.
|
AEP RIVER OPERATIONS
ThirdFirst Quarter of 20102011 Compared to ThirdFirst Quarter of 20092010
Net Income Before Extraordinary Loss from our AEP River Operations segment increased from $10 million in 2009 to $14$3 million in 2010 to $7 million in 2011 primarily due to improvedstrong freight demand driven by increased grain freight rates and increased volumes. Barge volumes increased 25% due to increased barge fleet, towboat additions and the earlier-than-normal harvest season.coal exports partially offset by higher operating expenses.
Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009
Income Before Extraordinary Loss from our AEP River Operations segment decreased from $22 million in 2009 to $16 million in 2010 primarily due to expenses related to the cost reduction initiatives, increased interest expense on new equipment financing and a gain on the sale of two older towboats in 2009.
GENERATION AND MARKETING
ThirdFirst Quarter of 20102011 Compared to ThirdFirst Quarter of 20092010
Net Income Before Extraordinary Loss from our Generation and Marketing segment decreased from $5$10 million in 20092010 to $0$1 million in 20102011 primarily due to reduced inception gains from ERCOT marketing activities and lower gross margins at the Oklaunion Plant.
Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009
Income Before Extraordinary Loss from our Generation and Marketing segment decreased from $33 million in 2009 to $17 million in 2010 primarily due to reduced inception gains from ERCOT marketing activities partially offset by improved plant performance, hedging activities on our generation assets and increased income from our wind farm operations.
ALL OTHER
ThirdFirst Quarter of 20102011 Compared to ThirdFirst Quarter of 20092010
Net Income Before Extraordinary Loss from All Other increaseddecreased from a loss of $17$11 million in 2009 to a gain of $2 million in 2010 primarily due to the recording of federal income tax adjustments.
Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009
Income Before Extraordinary Loss from All Other increased from a loss of $45 million in 2009 to a loss of $10$31 million in 20102011 primarily due to $16 million in pretax gains ($10 million, net of tax) on the sale of our remaining 138,000 shares of ICElosses incurred in the second quarterFebruary 2011 settlement of 2010litigation with BOA and the recording of federal income tax adjustments.Enron.
AEP SYSTEM INCOME TAXES
ThirdFirst Quarter of 20102011 Compared to ThirdFirst Quarter of 20092010
Income Tax Expense increased $50$71 million in comparison to 20092010 primarily due to an increase in pretaxpre-tax book income and other book/the unrealized capital loss valuation allowance related to a deferred tax differences which are accounted for on a flow-through basis,asset associated with the settlement of litigation with BOA and Enron, offset in part by federal income tax adjustments.
Nine Months Ended September 30,the 2010 Compared to Nine Months Ended September 30, 2009
Income Tax Expense decreased $5 million in comparison to 2009 primarily due to a decrease in pretax book income and federal income tax adjustments, partially offset by the regulatory accounting treatment of state income taxes, other book/tax differences which are accounted for on a flow-through basis and the tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.
FINANCIAL CONDITION
We measure our financial condition by the strength of our balance sheet and the liquidity provided by our cash flows. Target debt to equity ratios are included in our credit arrangements as covenants that must be met for borrowing to continue.
DEBTLIQUIDITY AND EQUITY CAPITALIZATIONCAPITAL RESOURCES
| | September 30, 2010 | | | December 31, 2009 |
| | (dollars in millions) |
Long-term Debt, including amounts due within one year | | $ | 17,281 | | | | 53.2 | % | | $ | 17,498 | | | | 56.8 | % |
Short-term Debt | | | 1,466 | | | | 4.5 | | | | 126 | | | | 0.4 | |
Total Debt | | | 18,747 | | | | 57.7 | | | | 17,624 | | | | 57.2 | |
Preferred Stock of Subsidiaries | | | 60 | | | | 0.2 | | | | 61 | | | | 0.2 | |
AEP Common Equity | | | 13,656 | | | | 42.1 | | | | 13,140 | | | | 42.6 | |
| | | | | | | | | | | | | | | | |
Total Debt and Equity Capitalization | | $ | 32,463 | | | | 100.0 | % | | $ | 30,825 | | | | 100.0 | % |
Debt and Equity Capitalization
| | March 31, 2011 | | December 31, 2010 |
| | (dollars in millions) |
Long-term Debt, including amounts due within one year | $ | 17,052 | | 52.8 | % | | $ | 16,811 | | 52.8 | % |
Short-term Debt | | 1,433 | | 4.4 | | | | 1,346 | | 4.2 | |
Total Debt | | 18,485 | | 57.2 | | | | 18,157 | | 57.0 | |
Preferred Stock of Subsidiaries | | 60 | | 0.2 | | | | 60 | | 0.2 | |
AEP Common Equity | | 13,779 | | 42.6 | | | | 13,622 | | 42.8 | |
| | | | | | | | | | | |
Total Debt and Equity Capitalization | $ | 32,324 | | 100.0 | % | | $ | 31,839 | | 100.0 | % |
Our ratio of debt-to-total capital increased from 57% in 2010 to 57.2% in 2009 to 57.7% in 2010 primarily due to an increase in short-term debt of $750 million as a result of a change in an accounting standard applicable to our sale of receivables agreement and an increase of $594 million in commercial paper outstanding.2011.
LIQUIDITYLiquidity
Liquidity, or access to cash, is an important factor in determining our financial stability. We believe we have adequate liquidity under our existing credit facilities. At September 30, 2010,March 31, 2011, we had $3.4$3 billion in aggregate credit facility commitments to support our operations, including our obligation to make payment of $447 million due to an unfavorable judgment issued in October 2010 related to the Bank of America litigation. See "Enron Bankruptcy" section of Note 4.operations. Additional liquidity is available from cash from operations and a sale of receivables agreement. 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. So urcesSources of long-term funding include issuance of long-term debt, sale-leaseback or leasing agreements or common stock.
Credit Facilities
We manage our liquidity by maintaining adequate external financing commitments. At September 30, 2010,March 31, 2011, our available liquidity was approximately $3.2$2.6 billion as illustrated in the table below:
| | | Amount | | | Maturity |
| | | (in millions) | | | |
Commercial Paper Backup: | | | | | | |
| Revolving Credit Facility | | $ | 1,454 | | | April 2012 |
| Revolving Credit Facility | | | 1,500 | | | June 2013 |
Revolving Credit Facility | | | 478 | | April 2011 |
Total | | | 3,4322,954 | | | |
Cash and Cash Equivalents | | | 1,090625 | | | |
Total Liquidity Sources | | | 4,5223,579 | | | |
Less: | AEP Commercial Paper Outstanding | | | 713813 | | | |
| Letters of Credit Issued | | | 602124 | | | |
| | | | | | | |
Net Available Liquidity | | $ | 3,2072,642 | | | |
| | | | | | | |
We have credit facilities totaling $3.4$3 billion of which two $1.5 billion credit facilitiesto support our commercial paper program. The credit facilities allow us to issue letters of credit in an amount up to $1.35 billion.
In June 2010,March 2011, we terminated onea $478 million credit facility, used for letters of the $1.5 billion facilitiescredit to support variable rate debt, that was scheduled to mature in April 2011. In March 2011, and replaced it with a new $1.5 billion credit facility which matures in 2013. These credit facilities also allow us to havewe issued bilateral letters of credit issued in an amount up to $1.35 billion. In June 2010, we also reducedsupport the credit facility that matures in April 2011 from $627remarketing of $357 million to $478 million. This facility can be utilized for letters of credit or draws.the variable rate debt and reacquired $115 million which are held by a trustee on our behalf.
We use our commercial paper program to meet the short-term borrowing needs of our subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. The maximum amount of commercial paper outstanding during 2010the first quarter of 2011 was $868 million.$1.2 billion. The weighted-average interest rate for our commercial paper during 20102011 was 0.42%0.4%.
Securitized Accounts Receivables
In July 2010, we renewed our receivables securitization agreement. The agreement provides a commitment of $750 million from bank conduits to purchase receivables. A commitment of $375 million expires in July 2011 and the remaining commitment of $375 million expires in July 2013. We intend to extend or replace the agreement expiring in July 2011 on or before its maturity.
Debt Covenants and Borrowing Limitations
Our revolving credit agreements contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%. The method for calculating our outstanding debt and other capitalcapitalization is contractually defined in our revolving credit agreements. agreements. Debt as defined in the revolving credit agreements excludes junior subordinated debentures, securitization bonds and debt of AEP Credit. At September 30, 2010,March 31, 2011, this contractually-defined percentage was 54%53%. Nonperformance under these covenants could result in an event of default under these credit agreements. At September 30, 2010,March 31, 2011, we complied with all of the covenants con tainedcontained 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 in a majority of our non-exchange traded commodity contracts which would permit the lenders and counterparties to declare the outstanding amounts payable. However, a default under our non-exchange traded commodity contracts does not cause an event of default under our revolving credit agreements.
The revolving credit facilities do not permit the lenders to refuse a draw on either 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, 2010,March 31, 2011, we had not exceeded those authorized limits.
Dividend Policy and Restrictions
The Board of Directors declared a quarterly dividend of $0.46 per share in October 2010, a $0.04 increase from the prior quarter.April 2011. 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. OurAEP’s income derives from our common stock equity in the earnings of our utility subsidiaries. Various financing arrangements, charter provisions and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends.
We have the option to defer interest payments on the AEP Junior Subordinated Debentures 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 do not believe restrictions related to our various financing arrangements, charter provisions and regulatory requirements will have any significant impact on Parent’s ability to access cash to meet the payment of dividends on its common stock.
Credit Ratings
OurWe do not have any credit arrangements that would require material changes in payment schedules or terminations as a result of a credit downgrade, but our access to the commercial paper market may depend on our credit ratings. In addition, downgrades in our credit ratings by one of the rating agencies could increase our borrowing costs. Counterparty concerns about the credit quality of AEP or its utility subsidiaries could subject us to additional collateral demands under adequate assurance clauses under our derivative and non-derivative energy contracts.
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, |
| 2010 | | 2009 | | | | 2011 | | 2010 |
| (in millions) | | | | (in millions) |
Cash and Cash Equivalents at Beginning of Period | | $ | 490 | | | $ | 411 | | Cash and Cash Equivalents at Beginning of Period | | $ | 294 | | $ | 490 |
Net Cash Flows from Operating Activities | | | 1,702 | | | | 1,871 | | Net Cash Flows from Operating Activities | | 830 | | | 2 |
Net Cash Flows Used for Investing Activities | | | (1,575 | ) | | | (2,097 | ) | Net Cash Flows Used for Investing Activities | | (613) | | | (430) |
Net Cash Flows from Financing Activities | | | 473 | | | | 692 | | Net Cash Flows from Financing Activities | | | 114 | | | 756 |
Net Increase in Cash and Cash Equivalents | | | 600 | | | | 466 | | Net Increase in Cash and Cash Equivalents | | | 331 | | | 328 |
Cash and Cash Equivalents at End of Period | | $ | 1,090 | | | $ | 877 | | Cash and Cash Equivalents at End of Period | | $ | 625 | | $ | 818 |
Cash from operations and short-term borrowings provides working capital and allows us to meet other short-term cash needs.
Operating Activities | | | | | | |
| | | | | | |
| Nine Months Ended | |
| September 30, | |
| 2010 | | 2009 | |
| (in millions) | |
Net Income | | $ | 1,040 | | | $ | 1,126 | |
Depreciation and Amortization | | | 1,237 | | | | 1,200 | |
Other | | | (575 | ) | | | (455 | ) |
Net Cash Flows from Operating Activities | | $ | 1,702 | | | $ | 1,871 | |
| | | | | | | |
| | | Three Months Ended |
| | | March 31, |
| | | 2011 | | 2010 |
| | | (in millions) |
Net Income | | $ | 355 | | $ | 346 |
Depreciation and Amortization | | | 403 | | | 408 |
Other | | | 72 | | | (752) |
Net Cash Flows from Operating Activities | | $ | 830 | | $ | 2 |
Net Cash Flows from Operating Activities were $1.7 billion$830 million in 20102011 consisting primarily of Net Income of $1 billion$355 million and $1.2 billion$403 million of noncash Depreciation and Amortization. Other changes 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. Significant changes in other items include the favorable impact of decreases in fuel inventory and receivables from customers and the unfavorable impact of reducing accounts payable. Deferred Income Taxes increased primarily due to provisions in the Small Business Jobs Act and the Tax Relief, Unemployment Insurance Reauthorization and Jobs Creation Act, the settlement with BOA and Enron and an increase in tax versus book temporary differences from operations. In February 2011, we paid $425 million to BOA. $211 million of this payment was to settle litigation with BOA and Enron. The remaining $214 million to acquire cushion gas is discussed in Investing Activities below.
Net Cash Flows from Operating Activities were $2 million in 2010 consisting primarily of Net Income of $346 million and $408 million of noncash Depreciation and Amortization offset by $752 million in Other. Other includes a $656 million increase in securitized receivables under the application of new accounting guidance for “Transfers and Servicing” related to our sale of receivables agreement. SignificantOther changes in other items include an increase in under-recovered fuel primarily due to the deferral of fuel under the FAC in Ohio and higher fuel costs in Oklahoma and the favorable impac t of a decrease in fuel inventory. Deferred Income Taxes increased primarily due to bonus depreciation provisions in the American Recovery and Reinvestment Act of 2009, a change in tax accounting method and an increase in tax versus book temporary differences from operations. Due to these tax changes, Accrued Taxes, Net also increased primarily as a result of the receipt of a federal income tax refund of $419 million related to a net operating loss in 2009 that was carried back to 2007 and 2008. We also contributed $463 million to our qualified pension trust in 2010.
Net Cash Flows from Operating Activities were $1.9 billion in 2009 consisting primarily of Net Income of $1.1 billion and $1.2 billion of noncash Depreciation and Amortization. Other representsrepresent 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 the negative impact on cash of an increase in coal inventory reflecting decreased customer demand for electricity as the result of the economic slowdown and unfavorable weather conditions and an increase in under-recovered fuel primarily in Ohio and West Virginia.Virginia and the favorable impact of decreases in fuel inventory and tax receivables. Deferred Income Taxes increased primarily due to the American Recovery and Reinvestment Act of 2009 extending bonus depreciation provisions, a change in tax accounting method and an increase in tax versus book temporary differences from operations.
Investing Activities | | | | | | |
| | | | | | |
| Nine Months Ended | |
| September 30, | |
| 2010 | | 2009 | |
| (in millions) | |
Construction Expenditures | | $ | (1,629 | ) | | $ | (2,123 | ) |
Acquisitions of Nuclear Fuel | | | (69 | ) | | | (153 | ) |
Proceeds from Sales of Assets | | | 160 | | | | 258 | |
Other | | | (37 | ) | | | (79 | ) |
Net Cash Flows Used for Investing Activities | | $ | (1,575 | ) | | $ | (2,097 | ) |
| | | | | | | |
| | | Three Months Ended |
| | | March 31, |
| | | 2011 | | 2010 |
| | | (in millions) |
Construction Expenditures | | $ | (540) | | $ | (609) |
Acquisitions of Nuclear Fuel | | | (27) | | | (38) |
Acquisition of Cushion Gas from BOA | | | (214) | | | - |
Proceeds from Sales of Assets | | | 69 | | | 139 |
Other | | | 99 | | | 78 |
Net Cash Flows Used for Investing Activities | | $ | (613) | | $ | (430) |
Net Cash Flows Used for Investing Activities were $1.6 billion$613 million in 20102011 primarily due to Construction Expenditures for new generation, environmental, distribution and distributiontransmission investments. Proceeds from SalesWe paid $214 million to BOA for cushion gas as part of Assets in 2010 include $139 million for sales of Texas transmission assets to ETT.a litigation settlement.
Net Cash Flows Used for Investing Activities were $2.1 billion$430 million in 20092010 primarily due to Construction Expenditures for our new generation, environmental and distribution investments. Proceeds from Sales of Assets in 20092010 include $104 million relating to the sale of a portion of Turk Plant to joint owners and $95$135 million for sales of transmission assets in Texas to ETT.
Financing Activities | | | | | | |
| | | | | | |
| Nine Months Ended | |
| September 30, | |
| 2010 | | 2009 | |
| (in millions) | |
Issuance of Common Stock, Net | | $ | 65 | | | $ | 1,706 | |
Issuance/Retirement of Debt, Net | | | 1,087 | | | | (371 | ) |
Dividends Paid on Common Stock | | | (602 | ) | | | (564 | ) |
Other | | | (77 | ) | | | (79 | ) |
Net Cash Flows from Financing Activities | | $ | 473 | | | $ | 692 | |
| | | | | | | |
| | | Three Months Ended |
| | | March 31, |
| | | 2011 | | 2010 |
| | | (in millions) |
Issuance of Common Stock, Net | | $ | 31 | | $ | 26 |
Issuance/Retirement of Debt, Net | | | 324 | | | 952 |
Dividends Paid on Common Stock | | | (223) | | | (197) |
Other | | | (18) | | | (25) |
Net Cash Flows from Financing Activities | | $ | 114 | | $ | 756 |
Net Cash Flows from Financing Activities in 2011 were $114 million. Our net debt issuances were $324 million. The issuances included $600 million senior unsecured notes, $421 million of pollution control bonds and an increase in short-term borrowing of $87 million offset by retirements of $214 million of senior unsecured and debt notes, $471 million of pollution control bonds and $92 million of securitization bonds. We paid common stock dividends of $223 million. See Note 10 – Financing Activities for a complete discussion of long-term debt issuances and retirements.
Net Cash Flows from Financing Activities were $473$756 million in 2010. Our net debt issuances were $1.1 billion.$952 million. The net issuances included issuances of $884$500 million of senior unsecured notes and $326$158 million of pollution control bonds, a $594$280 million increase in commercial paper outstanding andoffset by retirements of $1 billion$490 million of senior unsecured notes, $148$86 million of securitization bonds and $222$54 million of pollution control bonds. Our short-term debt securitized by receivables increased $656 million under the application of new accounting guidance for “Transfers and Servicing” related to our sale of receivables agreement. We paid common stock dividends of $602$197 million. See Note 11 – Financing Activities for a complete discussion of long-term debt issuances and retire ments.
Net Cash Flows from Financing Activities in 2009 were $692 million. Issuance of Common Stock, Net of $1.7 billion is comprised of our issuance of 69 million shares of common stock with net proceeds of $1.64 billion and additional shares through our dividend reinvestment, employee savings and incentive programs. Our net debt retirements were $371 million. These retirements included a repayment of $2 billion outstanding under our credit facilities primarily from the proceeds of our common stock issuance and issuances of $1.6 billion of senior unsecured and debt notes and $327 million of pollution control bonds.
In October 2010, I&MApril 2011, APCo retired its $150$250 million 6%of 5.55% Senior Unsecured Notes due 2032.in 2011.
In November 2010, OPCoApril 2011, I&M retired $30 million of its $200 million 5.3% Senior Unsecured Notes due 2010.DCC Fuel debt notes.
OFF-BALANCE SHEET ARRANGEMENTS
In prior periods, under a limited set of circumstances, we entered into off-balance sheet arrangements for various reasons including accelerating cash collections, reducing operational expenses and spreading 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 transfers of customer accounts receivable that we enter in the normal course of business. The following identifies significant off-balance sheet arrangements:
| September 30, | | December 31, | | | | March 31, | | December 31, |
| 2010 | | 2009 | | | | 2011 | | 2010 |
| (in millions) | | | | (in millions) |
AEP Credit Accounts Receivable Purchase Commitments | | $ | - | | | $ | 631 | | |
Rockport Plant Unit 2 Future Minimum Lease Payments | | | 1,846 | | | | 1,920 | | Rockport Plant Unit 2 Future Minimum Lease Payments | | $ | 1,774 | | $ | 1,774 |
Railcars Maximum Potential Loss From Lease Agreement | | | 25 | | | | 25 | | Railcars Maximum Potential Loss From Lease Agreement | | 25 | | | 25 |
Effective January 1, 2010, we record the receivables and debt related to AEP Credit on our Condensed Consolidated Balance Sheet. 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”Analysis” in the 20092010 Annual Report.
SUMMARYCONTRACTUAL OBLIGATION INFORMATION
A summary of our contractual obligations is included in our 20092010 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.
MINE SAFETY INFORMATION
The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations. The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters. SWEPCo, through its ownership of DHLC, CSPCo, through its ownership of Conesville Coal Preparation Company (CCPC), and OPCo, through its use of the ConnorConner Run fly ash impoundment, are subject to the provisions of the Mine Act.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. DHLC, CCPC and ConnorConner Run received the following notices of violation and proposed assessments under the Mine Act for the quarter ended September 30, 2010:March 31, 2011:
| | | DHLC | | CCPC | | Conner Run |
Number of Citations for Violations of Mandatory Health or | | | | | | | | | |
| Safety Standards under 104 * | | | 7- | | | - | | | - |
Number of Orders Issued under 104(b) * | | | - | | | - | | | - |
Number of Citations and Orders for Unwarrantable Failure | | | | | | | | | |
| to Comply with Mandatory Health or Safety Standards under104(d) * | | | 1 | | | | | | |
| 104(d) * | | | - | | | | | | - |
Number of Flagrant Violations under 110(b)(2) * | | | - | | | - | | | - |
Number of Imminent Danger Orders Issued under 107(a) * | | | - | | | - | | | - |
Total Dollar Value of Proposed Assessments | | $ | 11,4722,144 | | $ | - | | $ | - |
Number of Mining-related Fatalities | | | - | | | - | | | - |
| | | | | | | | | |
* References to sections under the Mine Act | | | | | | | | | |
DHLC currently has twoa legal actionsaction pending before the Mine Safety and Health Administration (MSHA) challenging four violations issued by MSHA following an employee fatality in March 2009. A second legal action pending before MSHA relates to a citation issued as a result of a dragline boom issue.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
See the “Critical Accounting Policies and Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations”Analysis” in the 20092010 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.
NEW ACCOUNTING PRONOUNCEMENTS
New Accounting Pronouncements Adopted During 2010
We adopted ASU 2009-16 “Transfers and Servicing” effective January 1, 2010. The adoption of this standard resulted in AEP Credit’s transfers of future receivables being accounted for as financings with the receivables and short-term debt recorded on our balance sheet.
We adopted the prospective provisions of ASU 2009-17 “Consolidations” effective January 1, 2010. We no longer consolidate DHLC effective with the adoption of this standard.
See Note 2 for further discussion of accounting pronouncements.
Future Accounting Changes
The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, 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, financial statements, contingencies, financial instruments, emission allowances, fair value measurements, leases, insurance, hedge accounting, consolidation policy and discontinued operations. 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.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK MANAGEMENT ACTIVITIES
Market Risks
Our Utility Operations segment is exposed to certain market risks as a major power producer and transacts in wholesale electricity, coal and emission allowance trading and marketing contracts. These risks include commodity price risk, interest rate risk and credit risk. In addition, we are 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 and to a lesser extent Ohio in PJM and MISO, primarily transacts in wholesale energy 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 gradually settle and completely expire in the fourth quarter of 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 and emission 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 procedure s.procedures. The CORC consists of our Executive Vice President, - Generation,
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 following table summarizes the reasons for changes in total mark-to-market (MTM) value as compared to December 31, 2009:2010:
| MTM Risk Management Contract Net Assets (Liabilities) |
| Nine Months Ended September 30, 2010 |
| (in millions) |
| | | | Generation | | | | |
| | Utility | and | | |
| | Operations | Marketing | All Other | Total |
Total MTM Risk Management Contract Net Assets (Liabilities) | | | | | | | | | | | |
| at December 31, 2009 | $ | 134 | | $ | 147 | | $ | (3) | | $ | 278 |
(Gain) Loss from Contracts Realized/Settled During the Period and | | | | | | | | | | | |
| Entered in a Prior Period | | (62) | | | (13) | | | 5 | | | (70) |
Fair Value of New Contracts at Inception When Entered During the Period (a) | | 15 | | | 8 | | | - | | | 23 |
Net Option Premiums Received for Unexercised or Unexpired | | | | | | | | | | | |
| Option Contracts Entered During the Period | | (1) | | | - | | | - | | | (1) |
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b) | | (2) | | | (2) | | | - | | | (4) |
Changes in Fair Value Due to Market Fluctuations During thePeriod (c) | 11 | | | 2 | | | - | | | 13 |
Changes in Fair Value Allocated to Regulated Jurisdictions (d) | | 25 | | | - | | | - | | | 25 |
Total MTM Risk Management Contract Net Assets at September 30, 2010 | $ | 120 | | $ | 142 | | $ | 2 | | | 264 |
| | | | | | | | | | | | |
Commodity Cash Flow Hedge Contracts | | | | | | | | | | | 3 |
Interest Rate and Foreign Currency Cash Flow Hedge Contracts | | | | | | | | | | | (6) |
Fair Value Hedge Contracts | | | | | | | | | | | 7 |
Collateral Deposits | | | | | | | | | | | 208 |
Total MTM Derivative Contract Net Assets at September 30, 2010 | | | | | | | | | | $ | 476 |
| MTM Risk Management Contract Net Assets (Liabilities) |
| Three Months Ended March 31, 2011 |
| |
| | | | Generation | | | | |
| | Utility | and | | |
| | Operations | Marketing | All Other | Total |
| | (in millions) |
Total MTM Risk Management Contract Net Assets | | | | | | | | | | | |
| at December 31, 2010 | $ | 91 | | $ | 140 | | $ | 2 | | $ | 233 |
(Gain) Loss from Contracts Realized/Settled During the Period and | | | | | | | | | | | |
| Entered in a Prior Period | | (20) | | | (7) | | | (1) | | | (28) |
Fair Value of New Contracts at Inception When Entered During the | | | | | | | | | | | |
| Period (a) | | 2 | | | - | | | - | | | 2 |
Net Option Premiums Received for Unexercised or Unexpired | | | | | | | | | | | |
| Option Contracts Entered During the Period | | - | | | - | | | - | | | - |
Changes in Fair Value Due to Market Fluctuations During the | | | | | | | | | | | |
| Period (b) | | 4 | | | 5 | | | - | | | 9 |
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | | 13 | | | - | | | - | | | 13 |
Total MTM Risk Management Contract Net Assets | | | | | | | | | | | |
| at March 31, 2011 | $ | 90 | | $ | 138 | | $ | 1 | | | 229 |
| | | | | | | | | | | | |
Commodity Cash Flow Hedge Contracts | | | | | | | | | | | 12 |
Interest Rate and Foreign Currency Cash Flow Hedge Contracts | | | | | | | | | | | (3) |
Fair Value Hedge Contracts | | | | | | | | | | | 4 |
Collateral Deposits | | | | | | | | | | | 63 |
Total MTM Derivative Contract Net Assets at March 31, 2011 | | | | | | | | | | $ | 305 |
(a) | Reflects fair value on primarily 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) | Reflects changes in methodology in calculating the credit and discounting liability fair value adjustments. |
(c) | Market fluctuations are attributable to various factors such as supply/demand, weather, etc. |
(d)(c) | 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. |
See Note 87 – Derivatives and Hedging and Note 98 – Fair Value Measurements for additional information related to our risk management contracts. The following tables and discussion provide information on our credit risk and market volatility risk.
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 Investors Service, Standard & Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.
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. As of September 30, 2010,March 31, 2011, our credit exposure net of collateral to sub investment grade counterparties was approximately 8.9%7.93%, 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). As of September 30, 2010,March 31, 2011, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable:
| | | Exposure | | | | | | Number of | | Net Exposure | | | Exposure | | | | | | Number of | | Net Exposure |
| | Before | | | Counterparties | of | | Before | | | Counterparties | of |
| | Credit | Credit | Net | >10% of | Counterparties | | Credit | Credit | Net | >10% of | Counterparties |
Counterparty Credit Quality | Counterparty Credit Quality | Collateral | Collateral | Exposure | Net Exposure | >10% | Counterparty Credit Quality | Collateral | Collateral | Exposure | Net Exposure | >10% |
| | | | | | | | | | | | | | | | | |
| | | (dollars in millions) | | | (in millions, except number of counterparties) |
Investment Grade | Investment Grade | | $ | 801 | | $ | 41 | | $ | 760 | | 2 | | $ | 221 | Investment Grade | | $ | 551 | | $ | 9 | | $ | 542 | | 1 | | $ | 129 |
Split Rating | Split Rating | | 4 | | - | | 4 | | 1 | | 4 | Split Rating | | 2 | | - | | 2 | | 1 | | 2 |
Noninvestment Grade | Noninvestment Grade | | 2 | | 1 | | 1 | | 2 | | 1 | Noninvestment Grade | | 7 | | 1 | | 6 | | 3 | | 6 |
No External Ratings: | No External Ratings: | | | | | | | | | | | No External Ratings: | | | | | | | | | | |
| Internal Investment Grade | | 210 | | - | | 210 | | 2 | | 133 | Internal Investment Grade | | 185 | | 2 | | 183 | | 4 | | 118 |
| Internal Noninvestment Grade | | | 104 | | | 11 | | | 93 | | | 4 | | | 72 | Internal Noninvestment Grade | | | 70 | | | 13 | | | 57 | | | 1 | | | 31 |
Total as of September 30, 2010 | | $ | 1,121 | | $ | 53 | | $ | 1,068 | | | 11 | | $ | 431 | |
Total as of March 31, 2011 | | Total as of March 31, 2011 | | $ | 815 | | $ | 25 | | $ | 790 | | | 10 | | $ | 286 |
| | | | | | | | | | | | | | | | | | | | | | |
Total as of December 31, 2009 | | $ | 846 | | $ | 58 | | $ | 788 | | | 12 | | $ | 317 | |
Total as of December 31, 2010 | | Total as of December 31, 2010 | | $ | 946 | | $ | 33 | | $ | 913 | | | 7 | | $ | 347 |
Value at Risk (VaR) Associated with Risk Management Contracts
We use a risk measurement model, which calculates 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, as of September 30, 2010,March 31, 2011, 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 trading portfolio for the periods indicated:
VaR Model
Nine Months Ended | | | | | Twelve Months Ended |
September 30, 2010 | | | | | December 31, 2009 |
(in millions) | | | | | (in millions) |
End | | High | | Average | | Low | | | | | End | | High | | Average | | Low |
$- | | $2 | | $1 | | $- | | | | | $1 | | $2 | | $1 | | $- |
Three Months Ended | | Twelve Months Ended |
March 31, 2011 | | December 31, 2010 |
End | | High | | Average | | Low | | End | | High | | Average | | Low |
(in millions) | | (in millions) |
$ | - | | $ | 1 | | $ | - | | $ | - | | $ | - | | $ | 2 | | $ | 1 | | $ | - |
We back-test our VaR results against performance due to actual price movements. Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.
As our VaR calculation captures recent price movements, we also perform regular stress testing of the portfolio to understand our exposure to extreme price movements. We employ a historical-based method whereby the current portfolio is subjected to actual, observed price movements from the last four years in order to ascertain which historical price movements translated into the largest potential MTM loss. We then research the underlying positions, price movesmovements and market events that created the most significant exposure and report the findings to the Risk Executive Committee or the CORC as appropriate.
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’sour 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. As calculated on debt outstanding for both September 30, 2010as of March 31, 2011 and December 31, 2009,2010, the estimated EaR on our debt portfolio for the following twelve months was $4 million.$3 million and $5 million, respectively.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | |
CONDENSED CONSOLIDATED STATEMENTS OF INCOME | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in millions, except per-share and share amounts) | |
(Unaudited) | |
| | | | | | |
| | 2011 | | | 2010 | |
REVENUES | | | | | | |
Utility Operations | | $ | 3,497 | | | $ | 3,406 | |
Other Revenues | | | 233 | | | | 163 | |
TOTAL REVENUES | | | 3,730 | | | | 3,569 | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 1,056 | | | | 1,014 | |
Purchased Electricity for Resale | | | 275 | | | | 238 | |
Other Operation | | | 686 | | | | 673 | |
Maintenance | | | 265 | | | | 271 | |
Depreciation and Amortization | | | 403 | | | | 408 | |
Taxes Other Than Income Taxes | | | 213 | | | | 207 | |
TOTAL EXPENSES | | | 2,898 | | | | 2,811 | |
| | | | | | | | |
OPERATING INCOME | | | 832 | | | | 758 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest and Investment Income | | | 2 | | | | 3 | |
Carrying Costs Income | | | 15 | | | | 14 | |
Allowance for Equity Funds Used During Construction | | | 20 | | | | 24 | |
Interest Expense | | | (242 | ) | | | (250 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS | | | 627 | | | | 549 | |
| | | | | | | | |
Income Tax Expense | | | 278 | | | | 207 | |
Equity Earnings of Unconsolidated Subsidiaries | | | 6 | | | | 4 | |
| | | | | | | | |
NET INCOME | | | 355 | | | | 346 | |
| | | | | | | | |
Less: Net Income Attributable to Noncontrolling Interests | | | 1 | | | | 1 | |
| | | | | | | | |
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS | | | 354 | | | | 345 | |
| | | | | | | | |
Less: Preferred Stock Dividend Requirements of Subsidiaries | | | 1 | | | | 1 | |
| | | | | | | | |
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 353 | | | $ | 344 | |
| | | | | | | | |
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING | | | 481,144,270 | | | | 478,429,535 | |
| | | | | | | | |
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON | | | | | | | | |
SHAREHOLDERS | | $ | 0.73 | | | $ | 0.72 | |
| | | | | | | | |
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING | | | 481,365,806 | | | | 478,844,632 | |
| | | | | | | | |
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON | | | | | | | | |
SHAREHOLDERS | | $ | 0.73 | | | $ | 0.72 | |
| | | | | | | | |
CASH DIVIDENDS DECLARED PER SHARE | | $ | 0.46 | | | $ | 0.41 | |
| | | | | | | | |
See Condensed Notes to Condensed Consolidated Financial Statements. | | | | | | | | |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES |
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY AND |
COMPREHENSIVE INCOME (LOSS) |
For the Three Months Ended March 31, 2011 and 2010 |
(in millions) |
(Unaudited) |
|
| AEP Common Shareholders | | | | |
| Common Stock | | | | | | Accumulated | | | | |
| | | | | | | | | Other | | | | |
| | | | | Paid-in | | Retained | | Comprehensive | | Noncontrolling | | |
| Shares | | Amount | | Capital | | Earnings | | Income (Loss) | | Interests | | Total |
TOTAL EQUITY – DECEMBER 31, 2009 | | 498 | | $ | 3,239 | | $ | 5,824 | | $ | 4,451 | | $ | (374) | | $ | - | | $ | 13,140 |
| | | | | | | | | | | | | | | | | | | | |
Issuance of Common Stock | | 1 | | | 5 | | | 21 | | | | | | | | | | | | 26 |
Common Stock Dividends | | | | | | | | | | | (196) | | | | | | (1) | | | (197) |
Preferred Stock Dividend Requirements of | | | | | | | | | | | | | | | | | | | | |
| Subsidiaries | | | | | | | | | | | (1) | | | | | | | | | (1) |
Other Changes in Equity | | | | | | | | 2 | | | (2) | | | | | | | | | - |
SUBTOTAL – EQUITY | | | | | | | | | | | | | | | | | | | | 12,968 |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of | | | | | | | | | | | | | | | | | | | | |
| Taxes: | | | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges, Net of Tax of $2 | | | | | | | | | | | | | | 4 | | | | | | 4 |
| | Securities Available for Sale, Net of Tax of $- | | | | | | | | | | | | | | 1 | | | | | | 1 |
| | Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | |
| | | Costs, Net of Tax of $3 | | | | | | | | | | | | | | 5 | | | | | | 5 |
NET INCOME | | | | | | | | | | | 345 | | | | | | 1 | | | 346 |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | 356 |
| | | | | | | | | | | | | | | | | | | | |
TOTAL EQUITY – MARCH 31, 2010 | | 499 | | $ | 3,244 | | $ | 5,847 | | $ | 4,597 | | $ | (364) | | $ | - | | $ | 13,324 |
| | | | | | | | | | | | | | | | | | | | |
TOTAL EQUITY – DECEMBER 31, 2010 | | 501 | | $ | 3,257 | | $ | 5,904 | | $ | 4,842 | | $ | (381) | | $ | - | | $ | 13,622 |
| | | | | | | | | | | | | | | | | | | | |
Issuance of Common Stock | | 1 | | | 6 | | | 25 | | | | | | | | | | | | 31 |
Common Stock Dividends | | | | | | | | | | | (222) | | | | | | (1) | | | (223) |
Preferred Stock Dividend Requirements of | | | | | | | | | | | | | | | | | | | | |
| Subsidiaries | | | | | | | | | | | (1) | | | | | | | | | (1) |
Other Changes in Equity | | | | | | | | (13) | | | | | | | | | | | | (13) |
SUBTOTAL – EQUITY | | | | | | | | | | | | | | | | | | | | 13,416 |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of | | | | | | | | | | | | | | | | | | | | |
| Taxes: | | | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges, Net of Tax of $1 | | | | | | | | | | | | | | 1 | | | | | | 1 |
| | Securities Available for Sale, Net of Tax of $- | | | | | | | | | | | | | | 1 | | | | | | 1 |
| | Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | |
| | | Costs, Net of Tax of $3 | | | | | | | | | | | | | | 6 | | | | | | 6 |
NET INCOME | | | | | | | | | | | 354 | | | | | | 1 | | | 355 |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | 363 |
| | | | | | | | | | | | | | | | | | | | |
TOTAL EQUITY – MARCH 31, 2011 | | 502 | | $ | 3,263 | | $ | 5,916 | | $ | 4,973 | | $ | (373) | | $ | - | | $ | 13,779 |
| | | | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Consolidated Financial Statements. | | | | | | | | | | | | |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
ASSETS | |
March 31, 2011 and December 31, 2010 | |
(in millions) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 625 | | | $ | 294 | |
Other Temporary Investments | | | | | | | | |
(March 31, 2011 and December 31, 2010 amounts include $212 and $287, respectively, related to Transition Funding and EIS) | | | 296 | | | | 416 | |
Accounts Receivable: | | | | | | | | |
Customers | | | 627 | | | | 683 | |
Accrued Unbilled Revenues | | | 138 | | | | 195 | |
Pledged Accounts Receivable - AEP Credit | | | 914 | | | | 949 | |
Miscellaneous | | | 106 | | | | 137 | |
Allowance for Uncollectible Accounts | | | (36 | ) | | | (41 | ) |
Total Accounts Receivable | | | 1,749 | | | | 1,923 | |
Fuel | | | 714 | | | | 837 | |
Materials and Supplies | | | 614 | | | | 611 | |
Risk Management Assets | | | 193 | | | | 232 | |
Accrued Tax Benefits | | | 301 | | | | 389 | |
Regulatory Asset for Under-Recovered Fuel Costs | | | 70 | | | | 81 | |
Margin Deposits | | | 70 | | | | 88 | |
Prepayments and Other Current Assets | | | 157 | | | | 145 | |
TOTAL CURRENT ASSETS | | | 4,789 | | | | 5,016 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Generation | | | 24,766 | | | | 24,352 | |
Transmission | | | 8,677 | | | | 8,576 | |
Distribution | | | 14,338 | | | | 14,208 | |
Other Property, Plant and Equipment (including nuclear fuel and coal mining) | | | 3,835 | | | | 3,846 | |
Construction Work in Progress | | | 2,480 | | | | 2,758 | |
Total Property, Plant and Equipment | | | 54,096 | | | | 53,740 | |
Accumulated Depreciation and Amortization | | | 18,330 | | | | 18,066 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | | | 35,766 | | | | 35,674 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 4,957 | | | | 4,943 | |
Securitized Transition Assets | | | 1,707 | | | | 1,742 | |
Spent Nuclear Fuel and Decommissioning Trusts | | | 1,559 | | | | 1,515 | |
Goodwill | | | 76 | | | | 76 | |
Long-term Risk Management Assets | | | 359 | | | | 410 | |
Deferred Charges and Other Noncurrent Assets | | | 1,347 | | | | 1,079 | |
TOTAL OTHER NONCURRENT ASSETS | | | 10,005 | | | | 9,765 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 50,560 | | | $ | 50,455 | |
| | | | | | | | |
See Condensed Notes to Condensed Consolidated Financial Statements. | | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | |
CONDENSED CONSOLIDATED STATEMENTS OF INCOME | |
For the Three and Nine Months Ended September 30, 2010 and 2009 | |
(in millions, except per-share and share amounts) | |
(Unaudited) | |
| | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended | |
| | 2010 | | | 2009 | | | 2010 | | | 2009 | |
REVENUES | | | | | | | | | | | | |
Utility Operations | | $ | 3,876 | | | $ | 3,364 | | | $ | 10,468 | | | $ | 9,666 | |
Other Revenues | | | 188 | | | | 183 | | | | 525 | | | | 541 | |
TOTAL REVENUES | | | 4,064 | | | | 3,547 | | | | 10,993 | | | | 10,207 | |
EXPENSES | | | | | | | | | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 1,189 | | | | 931 | | | | 3,098 | | | | 2,624 | |
Purchased Electricity for Resale | | | 247 | | | | 247 | | | | 712 | | | | 800 | |
Other Operation | | | 707 | | | | 642 | | | | 2,374 | | | | 1,890 | |
Maintenance | | | 262 | | | | 255 | | | | 776 | | | | 821 | |
Depreciation and Amortization | | | 424 | | | | 421 | | | | 1,237 | | | | 1,200 | |
Taxes Other Than Income Taxes | | | 210 | | | | 193 | | | | 619 | | | | 582 | |
TOTAL EXPENSES | | | 3,039 | | | | 2,689 | | | | 8,816 | | | | 7,917 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 1,025 | | | | 858 | | | | 2,177 | | | | 2,290 | |
| | | | | | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | | | | | |
Interest and Investment Income | | | 3 | | | | 5 | | | | 24 | | | | 5 | |
Carrying Costs Income | | | 18 | | | | 12 | | | | 51 | | | | 33 | |
Allowance for Equity Funds Used During Construction | | | 17 | | | | 23 | | | | 60 | | | | 59 | |
Interest Expense | | | (251 | ) | | | (248 | ) | | | (750 | ) | | | (726 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS | | | 812 | | | | 650 | | | | 1,562 | | | | 1,661 | |
| | | | | | | | | | | | | | | | |
Income Tax Expense | | | 258 | | | | 208 | | | | 530 | | | | 535 | |
Equity Earnings of Unconsolidated Subsidiaries | | | 3 | | | | 4 | | | | 8 | | | | 5 | |
| | | | | | | | | | | | | | | | |
INCOME BEFORE EXTRAORDINARY LOSS | | | 557 | | | | 446 | | | | 1,040 | | | | 1,131 | |
| | | | | | | | | | | | | | | | |
EXTRAORDINARY LOSS, NET OF TAX | | | - | | | | - | | | | - | | | | (5 | ) |
| | | | | | | | | | | | �� | | | | |
NET INCOME | | | 557 | | | | 446 | | | | 1,040 | | | | 1,126 | |
| | | | | | | | | | | | | | | | |
Less: Net Income Attributable to Noncontrolling Interests | | | 1 | | | | 2 | | | | 3 | | | | 5 | |
| | | | | | | | | | | | | | | | |
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS | | | 556 | | | | 444 | | | | 1,037 | | | | 1,121 | |
| | | | | | | | | | | | | | | | |
Less: Preferred Stock Dividend Requirements of Subsidiaries | | | 1 | | | | 1 | | | | 2 | | | | 2 | |
| | | | | | | | | | | | | | | | |
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 555 | | | $ | 443 | | | $ | 1,035 | | | $ | 1,119 | |
| | | | | | | | | | | | | | | | |
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING | | | 479,578,139 | | | | 476,948,143 | | | | 479,023,690 | | | | 452,255,119 | |
| | | | | | | | | | | | | | | | |
BASIC EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | | | | | | | | | | | | | | | |
Income Before Extraordinary Loss | | $ | 1.16 | | | $ | 0.93 | | | $ | 2.16 | | | $ | 2.48 | |
Extraordinary Loss, Net of Tax | | | - | | | | - | | | | - | | | | (0.01 | ) |
| | | | | | | | | | | | | | | | |
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | $ | 1.16 | | | $ | 0.93 | | | $ | 2.16 | | | $ | 2.47 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING | | | 479,750,447 | | | | 477,111,144 | | | | 479,261,415 | | | | 452,495,494 | |
| | | | | | | | | | | | | | | | |
DILUTED EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | | | | | | | | | | | | | | | | |
Income Before Extraordinary Loss | | $ | 1.16 | | | $ | 0.93 | | | $ | 2.16 | | | $ | 2.48 | |
Extraordinary Loss, Net of Tax | | | - | | | | - | | | | - | | | | (0.01 | ) |
| | | | | | | | | | | | | | | | |
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON | | | | | | | | | | | | | | | | |
SHAREHOLDERS | | $ | 1.16 | | | $ | 0.93 | | | $ | 2.16 | | | $ | 2.47 | |
| | | | | | | | | | | | | | | | |
CASH DIVIDENDS PAID PER SHARE | | $ | 0.42 | | | $ | 0.41 | | | $ | 1.25 | | | $ | 1.23 | |
| | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Consolidated Financial Statements. | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
LIABILITIES AND EQUITY | |
March 31, 2011 and December 31, 2010 | |
(dollars in millions) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
CURRENT LIABILITIES | | | |
Accounts Payable | | $ | 884 | | | $ | 1,061 | |
Short-term Debt: | | | | | | | | |
Securitized Debt for Receivables - AEP Credit | | | | 620 | | | | 690 | |
Other Short-term Debt | | | | 813 | | | | 656 | |
Total Short-term Debt | | | | 1,433 | | | | 1,346 | |
Long-term Debt Due Within One Year | | | 1,421 | | | | 1,309 | |
Risk Management Liabilities | | | 109 | | | | 129 | |
Customer Deposits | | | 275 | | | | 273 | |
Accrued Taxes | | | 669 | | | | 702 | |
Accrued Interest | | | 248 | | | | 281 | |
Regulatory Liability for Over-Recovered Fuel Costs | | | 20 | | | | 17 | |
Deferred Gain and Accrued Litigation Costs | | | - | | | | 448 | |
Other Current Liabilities | | | 930 | | | | 952 | |
TOTAL CURRENT LIABILITIES | | | 5,989 | | | | 6,518 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt | | | | | | | | |
(March 31, 2011 and December 31, 2010 amounts include $1,733 and $1,857, respectively, related to Transition Funding, DCC Fuel and Sabine) | | | 15,631 | | | | 15,502 | |
Long-term Risk Management Liabilities | | | 138 | | | | 141 | |
Deferred Income Taxes | | | 7,490 | | | | 7,359 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 3,204 | | | | 3,171 | |
Asset Retirement Obligations | | | 1,413 | | | | 1,394 | |
Employee Benefits and Pension Obligations | | | 1,863 | | | | 1,893 | |
Deferred Credits and Other Noncurrent Liabilities | | | 993 | | | | 795 | |
TOTAL NONCURRENT LIABILITIES | | | 30,732 | | | | 30,255 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 36,721 | | | | 36,773 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 60 | | | | 60 | |
| | | | | | | | |
Rate Matters (Note 2) | | | | | | | | |
Commitments and Contingencies (Note 3) | | | | | | | | |
| | | | | | | | |
EQUITY | | | | | | | | |
Common Stock – Par Value – $6.50 Per Share: | | | | | | | | |
| | 2011 | | | 2010 | | | | | | | | | |
Shares Authorized | | | 600,000,000 | | | | 600,000,000 | | | | | | | | | |
Shares Issued | | | 502,009,606 | | | | 501,114,881 | | | | | | | | | |
(20,307,725 shares were held in treasury at March 31, 2011 and December 31, 2010) | | | 3,263 | | | | 3,257 | |
Paid-in Capital | | | 5,916 | | | | 5,904 | |
Retained Earnings | | | 4,973 | | | | 4,842 | |
Accumulated Other Comprehensive Income (Loss) | | | (373 | ) | | | (381 | ) |
TOTAL AEP COMMON SHAREHOLDERS’ EQUITY | | | 13,779 | | | | 13,622 | |
| | | | | | | | |
TOTAL EQUITY | | | 13,779 | | | | 13,622 | |
| | | | | | | | |
TOTAL LIABILITIES AND EQUITY | | $ | 50,560 | | | $ | 50,455 | |
| | | | | | | | |
See Condensed Notes to Condensed Consolidated Financial Statements. | | | | | | | | |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES |
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY AND |
COMPREHENSIVE INCOME (LOSS) |
For the Nine Months Ended September 30, 2010 and 2009 |
(in millions) |
(Unaudited) |
|
| AEP Common Shareholders | | | | |
| Common Stock | | | | | | Accumulated | | | | |
| | | | | | | | | Other | | | | |
| | | | | Paid-in | | Retained | | Comprehensive | | Noncontrolling | | |
| Shares | | Amount | | Capital | | Earnings | | Income (Loss) | | Interests | | Total |
TOTAL EQUITY – DECEMBER 31, 2008 | | 426 | | $ | 2,771 | | $ | 4,527 | | $ | 3,847 | | $ | (452) | | $ | 17 | | $ | 10,710 |
| | | | | | | | | | | | | | | | | | | | |
Issuance of Common Stock | | 71 | | | 464 | | | 1,294 | | | | | | | | | | | | 1,758 |
Common Stock Dividends | | | | | | | | | | | (559) | | | | | | (5) | | | (564) |
Preferred Stock Dividend Requirements of | | | | | | | | | | | | | | | | | | | | |
| Subsidiaries | | | | | | | | | | | (2) | | | | | | | | | (2) |
Purchase of JMG | | | | | | | | 55 | | | | | | | | | (18) | | | 37 |
Other Changes in Equity | | | | | | | | (50) | | | | | | | | | 1 | | | (49) |
SUBTOTAL – EQUITY | | | | | | | | | | | | | | | | | | | | 11,890 |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of | | | | | | | | | | | | | | | | | | | | |
| Taxes: | | | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges, Net of Tax of $3 | | | | | | | | | | | | | | 5 | | | | | | 5 |
| | Securities Available for Sale, Net of Tax of $5 | | | | | | | | | | | | | | 10 | | | | | | 10 |
| | Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | |
| | | Costs, Net of Tax of $18 | | | | | | | | | | | | | | 33 | | | | | | 33 |
NET INCOME | | | | | | | | | | | 1,121 | | | | | | 5 | | | 1,126 |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | 1,174 |
| | | | | | | | | | | | | | | | | | | | |
TOTAL EQUITY – SEPTEMBER 30, 2009 | | 497 | | $ | 3,235 | | $ | 5,826 | | $ | 4,407 | | $ | (404) | | $ | - | | $ | 13,064 |
| | | | | | | | | | | | | | | | | | | | |
TOTAL EQUITY – DECEMBER 31, 2009 | | 498 | | $ | 3,239 | | $ | 5,824 | | $ | 4,451 | | $ | (374) | | $ | - | | $ | 13,140 |
| | | | | | | | | | | | | | | | | | | | |
Issuance of Common Stock | | 2 | | | 13 | | | 53 | | | | | | | | | | | | 66 |
Common Stock Dividends | | | | | | | | | | | (599) | | | | | | (3) | | | (602) |
Preferred Stock Dividend Requirements of | | | | | | | | | | | | | | | | | | | | |
| Subsidiaries | | | | | | | | | | | (2) | | | | | | | | | (2) |
Other Changes in Equity | | | | | | | | 4 | | | | | | | | | | | | 4 |
SUBTOTAL – EQUITY | | | | | | | | | | | | | | | | | | | | 12,606 |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of | | | | | | | | | | | | | | | | | | | | |
| Taxes: | | | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges, Net of Tax of $1 | | | | | | | | | | | | | | 2 | | | | | | 2 |
| | Securities Available for Sale, Net of Tax of $5 | | | | | | | | | | | | | | (9) | | | | | | (9) |
| | Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | |
| | | Costs, Net of Tax of $9 | | | | | | | | | | | | | | 17 | | | | | | 17 |
NET INCOME | | | | | | | | | | | 1,037 | | | | | | 3 | | | 1,040 |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | 1,050 |
| | | | | | | | | | | | | | | | | | | | |
TOTAL EQUITY – SEPTEMBER 30, 2010 | | 500 | | $ | 3,252 | | $ | 5,881 | | $ | 4,887 | | $ | (364) | | $ | - | | $ | 13,656 |
| | | | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Consolidated Financial Statements. | | | | | | | | | | | | |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in millions) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 355 | | | $ | 346 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 403 | | | | 408 | |
Deferred Income Taxes | | | 330 | | | | 121 | |
Gain on Settlement with BOA and Enron | | | (51 | ) | | | - | |
Settlement of Litigation with BOA and Enron | | | (211 | ) | | | - | |
Carrying Costs Income | | | (15 | ) | | | (14 | ) |
Allowance for Equity Funds Used During Construction | | | (20 | ) | | | (24 | ) |
Mark-to-Market of Risk Management Contracts | | | 42 | | | | (69 | ) |
Amortization of Nuclear Fuel | | | 34 | | | | 30 | |
Property Taxes | | | (52 | ) | | | (53 | ) |
Fuel Over/Under-Recovery, Net | | | (27 | ) | | | (97 | ) |
Change in Other Noncurrent Assets | | | (3 | ) | | | (28 | ) |
Change in Other Noncurrent Liabilities | | | 77 | | | | 37 | |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 181 | | | | (617 | ) |
Fuel, Materials and Supplies | | | 121 | | | | 83 | |
Margin Deposits | | | 18 | | | | (20 | ) |
Accounts Payable | | | (126 | ) | | | (83 | ) |
Customer Deposits | | | 2 | | | | 5 | |
Accrued Taxes, Net | | | (96 | ) | | | 80 | |
Accrued Interest | | | (33 | ) | | | (34 | ) |
Other Current Assets | | | (16 | ) | | | (14 | ) |
Other Current Liabilities | | | (83 | ) | | | (55 | ) |
Net Cash Flows from Operating Activities | | | 830 | | | | 2 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (540 | ) | | | (609 | ) |
Change in Other Temporary Investments, Net | | | 73 | | | | 82 | |
Purchases of Investment Securities | | | (454 | ) | | | (445 | ) |
Sales of Investment Securities | | | 484 | | | | 473 | |
Acquisitions of Nuclear Fuel | | | (27 | ) | | | (38 | ) |
Acquisition of Cushion Gas from BOA | | | (214 | ) | | | - | |
Proceeds from Sales of Assets | | | 69 | | | | 139 | |
Other Investing Activities | | | (4 | ) | | | (32 | ) |
Net Cash Flows Used for Investing Activities | | | (613 | ) | | | (430 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Common Stock, Net | | | 31 | | | | 26 | |
Issuance of Long-term Debt | | | 1,014 | | | | 652 | |
Commercial Paper and Credit Facility Borrowings | | | 318 | | | | 24 | |
Change in Short-term Debt, Net | | | 244 | | | | 931 | |
Retirement of Long-term Debt | | | (777 | ) | | | (638 | ) |
Commercial Paper and Credit Facility Repayments | | | (475 | ) | | | (17 | ) |
Principal Payments for Capital Lease Obligations | | | (17 | ) | | | (24 | ) |
Dividends Paid on Common Stock | | | (223 | ) | | | (197 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (1 | ) | | | (1 | ) |
Net Cash Flows from Financing Activities | | | 114 | | | | 756 | |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 331 | | | | 328 | |
Cash and Cash Equivalents at Beginning of Period | | | 294 | | | | 490 | |
Cash and Cash Equivalents at End of Period | | $ | 625 | | | $ | 818 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 250 | | | $ | 271 | |
Net Cash Paid (Received) for Income Taxes | | | 2 | | | | (2 | ) |
Noncash Acquisitions Under Capital Leases | | | 24 | | | | 148 | |
Government Grants Included in Accounts Receivable at March 31, | | | 3 | | | | - | |
Construction Expenditures Included in Current Liabilities at March 31, | | | 220 | | | | 216 | |
Acquisition of Nuclear Fuel Included in Current Liabilities at March 31, | | | - | | | | 3 | |
| | | | | | | | |
See Condensed Notes to Condensed Consolidated Financial Statements. | | | | | | | | |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
ASSETS | |
September 30, 2010 and December 31, 2009 | |
(in millions) | |
(Unaudited) | |
| |
| | 2010 | | | 2009 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 1,090 | | | $ | 490 | |
Other Temporary Investments | | | 326 | | | | 363 | |
Accounts Receivable: | | | | | | | | |
Customers | | | 585 | | | | 492 | |
Accrued Unbilled Revenues | | | 137 | | | | 503 | |
Pledged Accounts Receivable - AEP Credit | | | 1,029 | | | | - | |
Miscellaneous | | | 108 | | | | 92 | |
Allowance for Uncollectible Accounts | | | (43 | ) | | | (37 | ) |
Total Accounts Receivable | | | 1,816 | | | | 1,050 | |
Fuel | | | 811 | | | | 1,075 | |
Materials and Supplies | | | 598 | | | | 586 | |
Risk Management Assets | | | 279 | | | | 260 | |
Accrued Tax Benefits | | | 165 | | | | 547 | |
Regulatory Asset for Under-Recovered Fuel Costs | | | 95 | | | | 85 | |
Margin Deposits | | | 86 | | | | 89 | |
Prepayments and Other Current Assets | | | 155 | | | | 211 | |
TOTAL CURRENT ASSETS | | | 5,421 | | | | 4,756 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Production | | | 24,079 | | | | 23,045 | |
Transmission | | | 8,470 | | | | 8,315 | |
Distribution | | | 13,940 | | | | 13,549 | |
Other Property, Plant and Equipment (including coal mining and nuclear fuel) | | | 3,867 | | | | 3,744 | |
Construction Work in Progress | | | 2,571 | | | | 3,031 | |
Total Property, Plant and Equipment | | | 52,927 | | | | 51,684 | |
Accumulated Depreciation and Amortization | | | 17,929 | | | | 17,340 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | | | 34,998 | | | | 34,344 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 4,745 | | | | 4,595 | |
Securitized Transition Assets | | | 1,788 | | | | 1,896 | |
Spent Nuclear Fuel and Decommissioning Trusts | | | 1,466 | | | | 1,392 | |
Goodwill | | | 76 | | | | 76 | |
Long-term Risk Management Assets | | | 488 | | | | 343 | |
Deferred Charges and Other Noncurrent Assets | | | 910 | | | | 946 | |
TOTAL OTHER NONCURRENT ASSETS | | | 9,473 | | | | 9,248 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 49,892 | | | $ | 48,348 | |
| | | | | | | | |
See Condensed Notes to Condensed Consolidated Financial Statements. | | | | | | | | |
| AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES |
| CONDENSED CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| September 30, 2010 and December 31, 2009 |
| (dollars in millions) |
| (Unaudited) |
| |
| | | 2010 | | 2009 |
| CURRENT LIABILITIES | | |
| Accounts Payable | | $ | 884 | | $ | 1,158 |
| Short-term Debt: | | | | | | |
| | General | | | | 716 | | | 126 |
| | Securitized Debt for Receivables - AEP Credit | | | | 750 | | | - |
| | | Total Short-term Debt | | | | 1,466 | | | 126 |
| Long-term Debt Due Within One Year | | | 1,286 | | | 1,741 |
| Risk Management Liabilities | | | 124 | | | 120 |
| Customer Deposits | | | 264 | | | 256 |
| Accrued Taxes | | | 470 | | | 632 |
| Accrued Interest | | | 255 | | | 287 |
| Regulatory Liability for Over-Recovered Fuel Costs | | | 11 | | | 76 |
| Liability Related to Litigation | | | 447 | | | - |
| Other Current Liabilities | | | 941 | | | 931 |
| TOTAL CURRENT LIABILITIES | | | 6,148 | | | 5,327 |
| | | | | | | |
| NONCURRENT LIABILITIES | | | | | | |
| Long-term Debt | | | | | | |
| | (September 30, 2010 amount includes $1,838 related to Transition Funding, DCC Fuel and Sabine) | | | 15,995 | | | 15,757 |
| Long-term Risk Management Liabilities | | | 167 | | | 128 |
| Deferred Income Taxes | | | 6,928 | | | 6,420 |
| Regulatory Liabilities and Deferred Investment Tax Credits | | | 3,109 | | | 2,909 |
| Asset Retirement Obligations | | | 1,296 | | | 1,254 |
| Employee Benefits and Pension Obligations | | | 1,729 | | | 2,189 |
| Deferred Credits and Other Noncurrent Liabilities | | | 804 | | | 1,163 |
| TOTAL NONCURRENT LIABILITIES | | | 30,028 | | | 29,820 |
| | | | | | | |
| TOTAL LIABILITIES | | | 36,176 | | | 35,147 |
| | | | | | | |
| Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 60 | | | 61 |
| | | | | | | |
| Rate Matters (Note 3) | | | | | | |
| Commitments and Contingencies (Note 4) | | | | | | |
| | | | | | | |
| EQUITY | | | | | | |
| Common Stock – Par Value – $6.50 Per Share: | | | | | | |
| | | | 2010 | | 2009 | | | | | | | |
| | Shares Authorized | 600,000,000 | | 600,000,000 | | | | | | | |
| | Shares Issued | 500,319,686 | | 498,333,265 | | | | | | | |
| (20,278,858 shares were held in treasury at September 30, 2010 and December 31, 2009) | | | 3,252 | | | 3,239 |
| Paid-in Capital | | | 5,881 | | | 5,824 |
| Retained Earnings | | | 4,887 | | | 4,451 |
| Accumulated Other Comprehensive Income (Loss) | | | (364) | | | (374) |
| TOTAL AEP COMMON SHAREHOLDERS’ EQUITY | | | 13,656 | | | 13,140 |
| | | | | | | |
| Noncontrolling Interests | | | - | | | - |
| | | | | | | |
| TOTAL EQUITY | | | 13,656 | | | 13,140 |
| | | | | | | |
| TOTAL LIABILITIES AND EQUITY | | $ | 49,892 | | $ | 48,348 |
| | | | | | | |
| See Condensed Notes to Condensed Consolidated Financial Statements. | | | | | | |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |
For the Nine Months Ended September 30, 2010 and 2009 | |
(in millions) | |
(Unaudited) | |
| |
| | 2010 | | | 2009 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 1,040 | | | $ | 1,126 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 1,237 | | | | 1,200 | |
Deferred Income Taxes | | | 404 | | | | 662 | |
Extraordinary Loss, Net of Tax | | | - | | | | 5 | |
Carrying Costs Income | | | (51 | ) | | | (33 | ) |
Allowance for Equity Funds Used During Construction | | | (60 | ) | | | (59 | ) |
Mark-to-Market of Risk Management Contracts | | | (108 | ) | | | (99 | ) |
Amortization of Nuclear Fuel | | | 113 | | | | 41 | |
Property Taxes | | | 157 | | | | 144 | |
Fuel Over/Under-Recovery, Net | | | (233 | ) | | | (377 | ) |
Pension Contributions to Qualified Plan Trust | | | (463 | ) | | | - | |
Change in Other Noncurrent Assets | | | (50 | ) | | | 13 | |
Change in Other Noncurrent Liabilities | | | 183 | | | | 164 | |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | (766 | ) | | | 68 | |
Fuel, Materials and Supplies | | | 240 | | | | (394 | ) |
Margin Deposits | | | 3 | | | | (15 | ) |
Accounts Payable | | | (163 | ) | | | (29 | ) |
Customer Deposits | | | 8 | | | | 11 | |
Accrued Taxes, Net | | | 223 | | | | (165 | ) |
Accrued Interest | | | (32 | ) | | | (38 | ) |
Other Current Assets | | | 35 | | | | (71 | ) |
Other Current Liabilities | | | (15 | ) | | | (283 | ) |
Net Cash Flows from Operating Activities | | | 1,702 | | | | 1,871 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (1,629 | ) | | | (2,123 | ) |
Change in Other Temporary Investments, Net | | | 63 | | | | 72 | |
Purchases of Investment Securities | | | (1,542 | ) | | | (573 | ) |
Sales of Investment Securities | | | 1,477 | | | | 524 | |
Acquisitions of Nuclear Fuel | | | (69 | ) | | | (153 | ) |
Acquisitions of Assets | | | (16 | ) | | | (70 | ) |
Proceeds from Sales of Assets | | | 160 | | | | 258 | |
Other Investing Activities | | | (19 | ) | | | (32 | ) |
Net Cash Flows Used for Investing Activities | | | (1,575 | ) | | | (2,097 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Common Stock, Net | | | 65 | | | | 1,706 | |
Issuance of Long-term Debt | | | 1,201 | | | | 1,912 | |
Borrowings from Revolving Credit Facilities | | | 195 | | | | 90 | |
Change in Short-term Debt, Net | | | 1,223 | | | | 347 | |
Retirement of Long-term Debt | | | (1,454 | ) | | | (659 | ) |
Repayments to Revolving Credit Facilities | | | (78 | ) | | | (2,061 | ) |
Principal Payments for Capital Lease Obligations | | | (74 | ) | | | (62 | ) |
Dividends Paid on Common Stock | | | (602 | ) | | | (564 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (2 | ) | | | (2 | ) |
Other Financing Activities | | | (1 | ) | | | (15 | ) |
Net Cash Flows from Financing Activities | | | 473 | | | | 692 | |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 600 | | | | 466 | |
Cash and Cash Equivalents at Beginning of Period | | | 490 | | | | 411 | |
Cash and Cash Equivalents at End of Period | | $ | 1,090 | | | $ | 877 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 755 | | | $ | 744 | |
Net Cash Paid (Received) for Income Taxes | | | (243 | ) | | | (74 | ) |
Noncash Acquisitions Under Capital Leases | | | 190 | | | | 53 | |
Construction Expenditures Included in Accounts Payable at September 30, | | | 229 | | | | 229 | |
| | | | | | | | |
See Condensed Notes to Condensed Consolidated Financial Statements. | | | | | | | | |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
INDEX TOOF CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
| |
1. | Significant Accounting Matters |
2. | New Accounting Pronouncements and Extraordinary Item |
3.2. | Rate Matters |
4. | |
3. | Commitments, Guarantees and Contingencies |
5. | |
4. | Acquisition and Dispositions |
6. | |
5. | Benefit Plans |
7. | |
6. | Business Segments |
8. | |
7. | Derivatives and Hedging |
9. | |
8. | Fair Value Measurements |
10. | |
9. | Income Taxes |
11. | |
10. | Financing Activities |
12. | |
11. | Cost Reduction Initiatives |
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 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 condensed consolidated 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. Net income for the three and nine months ended September 30, 2010March 31, 2011 is not necessarily indicative of results that may be expected for the year ending December 31, 2010.2011. The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 20092010 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 26, 2010.
Variable Interest Entities25, 2011.
Variable Interest Entities
The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Enti ties.Entities.” 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, the power to direct the VIE and other factors. We believe that significant assumptions and judgments were applied consistently. Also, see the “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.
We are the primary beneficiary of Sabine, DCC Fuel, LLC, DCC Fuel II LLC, AEP Credit, Transition Funding and a protected cell of EIS. As of January 1, 2010, we are no longer the primary beneficiary of DHLC as defined by the new accounting guidance for “Variable Interest Entities.” In addition, we have not provided material financial or other support to Sabine, DCC Fuel, LLC, DCC Fuel II LLC, Transition Funding, our protected cell of EIS and AEP Credit that was not previously contractually required. We hold a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series) and DHLC..
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 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. In addition, SWEPCo determines how much coal will be mined for each year. Based on these facts, management concluded that SWEPCo is the primary benefic iarybeneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the three months ended September 30,March 31, 2011 and 2010 and 2009 were $30$33 million and $34 million, respectively, and for the nine months ended September 30, 2010 and 2009 were $103 million and $95$43 million, respectively. See the tables below for the classification of Sabine’s assets and liabilities on our Condensed Consolidated Balance Sheets.
Our subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance. EIS has multiple protected cells. 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 our control and the structure of the protected cell and EIS, management concluded that we are the primary beneficiary of the protected cell and are required to consolidate its assets and liabilities. Our insurance premium paymentsexpense to the protected cell for the three months ended September 30,March 31, 2011 and 2010 and 2009 were $15 mill ion and $13 million, respectively, and for the nine months ended September 30, 2010 and 2009 were $33was $30 million and $30$18 million, respectively. See the tables below for the classification of the protected cell’s assets and liabilities on our Condensed Consolidated Balance Sheets. The amount reported as equity is the protected cell’s policy holders’ surplus.
I&M entered intohas a nuclear fuel sale and leaseback transactionlease agreement with DCC Fuel LLC. In April 2010, I&M entered into a nuclear fuel sale and leaseback transaction withLLC, DCC Fuel II LLC. DCC Fuel LLC and DCC Fuel IIIII LLC (collectively DCC Fuel) were. DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC are separate legal entities from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the DCC Fuel LLC and DCC Fuel II LLC leases are made semi-annually and began in April 2010.2010 and October 2010, respectively. Payments on the leasesDCC Fuel III LLC lease are made monthly and began in January 2011. Payments on the DCC Fuel III LLC lease for the ninethree months ended September 30, 2010March 31, 2011 were $22$6 million. No payments were made to DCC Fu el during the third quarter of 2010 and during the year 2009. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the 48, 54 and 54 month lease term, respectively. Based on our control of DCC Fuel, management has concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the tables below for the classification of DCC Fuel’s assets and liabilities on our Condensed Consolidated Balance Sheets.
AEP Credit is a wholly-owned subsidiary of AEP. AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements. AEP provides a minimum of 5% equity and up to 20% of AEP Credit’s short-term borrowing needs in excess of third party financings. Any third party financing of AEP Credit only has recourse to the receivables soldsecuritized for such financing. Based on our control of AEP Credit, management has concluded that we are the primary beneficiary and are required to consolidate its assets and liabilities. See the tables below for the classification of AEP Credit’s assets and liabilities on our Condensed Consolidated Balance Sheets. See the “ASU 2009-17 ‘Consolid ation’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010. Also, see “Sale of“Securitized Accounts Receivables – AEP Credit” section of Note 14 in the 2009 Annual Report for further information.10.
DHLC is a mining operator who sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and its voting rights equally. Each entity guarantees a 50% share of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. Based on the shared control of DHLC’s operations, management concluded as of January 1, 2010 that SWEPCo is no longer the primary beneficiary and is no longer required to consolidate DHLC. SWEPCo’s total billings fro m DHLC for the three months ended September 30, 2010 and 2009 were $14 million and $12 million, respectively, and for the nine months ended September 30, 2010 and 2009 were $40 million and $31 million, respectively. See the tables below for the classification of DHLC’s assets and liabilities on our Condensed Consolidated Balance Sheet at December 31, 2009 as well as our investment and maximum exposure as of September 30, 2010. As of January 1, 2010, DHLC is reported as an equity investment in Deferred Charges and Other Noncurrent Assets on our Condensed Consolidated Balance Sheet. Also, see the “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.
Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas restructuring law. Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC’s equity interest could potentially be significant. Therefore, TCC is required to consolidate Transition Funding. The securitized bonds totaled $1.8 billion and $1.8 billion at September 30,March 31, 2011 and December 31, 2010, respectively, and are included in current and long-term debt on the Condensed Consolidated Balance Sheets. Transition Funding has securitized transition assets of $1.8$1.7 billion and $1.7 billion at September 30,March 31, 2011 and December 31, 2010, respectively, which are presented separately on the face of the Condensed Consolidated Balance Sheets. The securitized transition a ssetsassets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to TCC or any other AEP entity. TCC acts as the servicer for Transition Funding’s securitized transition assetassets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs.
The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | | AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES |
VARIABLE INTEREST ENTITIES | VARIABLE INTEREST ENTITIES | | VARIABLE INTEREST ENTITIES |
September 30, 2010 | | |
March 31, 2011 | | March 31, 2011 |
(in millions) | (in millions) | | (in millions) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | SWEPCo | | I&M | | Protected Cell | | | | Transition | | | SWEPCo | | I&M | | Protected Cell | | | | Transition |
| | Sabine | | DCC Fuel | | of EIS | | AEP Credit | | Funding | | | Sabine | DCC Fuel | of EIS | AEP Credit | | Funding |
ASSETS | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current Assets | | | $ | 42 | | | $ | 92 | | | $ | 143 | | | $ | 1,004 | | | $ | 160 | | | $ | 40 | | $ | 107 | | $ | 146 | | $ | 902 | | $ | 130 |
Net Property, Plant and Equipment | | | | 142 | | | | 118 | | | | - | | | | - | | | | - | | | 142 | | 151 | | - | | - | | - |
Other Noncurrent Assets | | | | 35 | | | | 80 | | | | 1 | | | | 10 | | | | 1,791 | | | | 37 | | | 93 | | | 8 | | | - | | | 1,711 |
Total Assets | | | $ | 219 | | | $ | 290 | | | $ | 144 | | | $ | 1,014 | | | $ | 1,951 | | | $ | 219 | | $ | 351 | | $ | 154 | | $ | 902 | | $ | 1,841 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
LIABILITIES AND EQUITY | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current Liabilities | | | $ | 26 | | | $ | 65 | | | $ | 40 | | | $ | 961 | | | $ | 196 | | | $ | 44 | | $ | 81 | | $ | 62 | | $ | 824 | | $ | 202 |
Noncurrent Liabilities | | | | 193 | | | | 225 | | | | 90 | | | | 1 | | | | 1,741 | | | 175 | | 270 | | 74 | | 1 | | | 1,625 |
Equity | | | | - | | | | - | | | | 14 | | | | 52 | | | | 14 | | | | - | | | - | | | 18 | | | 77 | | | 14 |
Total Liabilities and Equity | | | $ | 219 | | | $ | 290 | | | $ | 144 | | | $ | 1,014 | | | $ | 1,951 | | | $ | 219 | | $ | 351 | | $ | 154 | | $ | 902 | | $ | 1,841 |
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | | AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES |
VARIABLE INTEREST ENTITIES | VARIABLE INTEREST ENTITIES | | VARIABLE INTEREST ENTITIES |
December 31, 2009 | | |
December 31, 2010 | | December 31, 2010 |
(in millions) | (in millions) | | (in millions) |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | SWEPCo | | SWEPCo | | I&M | | Protected Cell | | | SWEPCo | | I&M | | Protected Cell | | | | Transition |
| | Sabine | | DHLC | | DCC Fuel | | of EIS | | | Sabine | DCC Fuel | of EIS | AEP Credit | | Funding |
ASSETS | | | | | | | | | | | | | | | | | | | | | | | | |
Current Assets | | | $ | 51 | | | $ | 8 | | | $ | 47 | | | $ | 130 | | | $ | 50 | | $ | 92 | | $ | 131 | | $ | 924 | | $ | 214 |
Net Property, Plant and Equipment | | | | 149 | | | | 44 | | | | 89 | | | | - | | | 139 | | 173 | | - | | - | | | - |
Other Noncurrent Assets | | | | 35 | | | | 11 | | | | 57 | | | | 2 | | | | 34 | | | 112 | | | 1 | | | 10 | | | 1,746 |
Total Assets | | | $ | 235 | | | $ | 63 | | | $ | 193 | | | $ | 132 | | | $ | 223 | | $ | 377 | | $ | 132 | | $ | 934 | | $ | 1,960 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
LIABILITIES AND EQUITY | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current Liabilities | | | $ | 36 | | | $ | 17 | | | $ | 39 | | | $ | 36 | | | $ | 33 | | $ | 79 | | $ | 33 | | $ | 886 | | $ | 221 |
Noncurrent Liabilities | | | | 199 | | | | 38 | | | | 154 | | | | 74 | | | 190 | | 298 | | 85 | | 1 | | | 1,725 |
Equity | | | | - | | | | 8 | | | | - | | | | 22 | | | | - | | | - | | | 14 | | | 47 | | | 14 |
Total Liabilities and Equity | | | $ | 235 | | | $ | 63 | | | $ | 193 | | | $ | 132 | | | $ | 223 | | $ | 377 | | $ | 132 | | $ | 934 | | $ | 1,960 |
DHLC is a mining operator who sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and its voting rights equally. Each entity guarantees a 50% share of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo’s total billings from DHLC for the three months ended March 31, 2011 and 2010 were $13 million and $13 million, respectively. We are not required to consolidate DHLC as we are not the primary beneficiary, although we hold a significant variable interest in DHLC. Our equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on our Condensed Consolidated Balance Sheets.
Our investment in DHLC was:
| September 30, 2010 | | March 31, 2011 | | December 31, 2010 |
| As Reported on | | | | As Reported on | | | | As Reported on | | |
| the Consolidated | | Maximum | | the Consolidated | Maximum | | the Consolidated | | Maximum |
| Balance Sheet | | Exposure | | Balance Sheet | Exposure | | Balance Sheet | | Exposure |
| (in millions) | | (in millions) |
Capital Contribution from SWEPCo | | $ | 7 | | | $ | 7 | | $ | 8 | | $ | 8 | | $ | 6 | | $ | 6 |
Retained Earnings | | | 2 | | | | 2 | | | 1 | | 1 | | | 2 | | | 2 |
SWEPCo's Guarantee of Debt | | | - | | | | 42 | | | - | | | 46 | | | - | | | 48 |
| | | | | | | | | | | | | | | | | | |
Total Investment in DHLC | | $ | 9 | | | $ | 51 | | $ | 9 | | $ | 55 | | $ | 8 | | $ | 56 |
In September 2007, weWe and Allegheny Energy Inc. (AYE) formedhave a joint venture by creatingin Potomac-Appalachian Transmission Highline, LLC (PATH). In February 2011, FirstEnergy Corp. (FirstEnergy) completed its merger with AYE, under which AYE became a wholly-owned subsidiary of FirstEnergy. Also, in February 2011, PJM directed that work on the PATH project be suspended. PATH is a series limited liability company and was created to construct a high-voltage transmission line project in the PJM region. PATH consistsconsisted of the “Ohio Series,” the “West Virginia Series (PATH-WV),” both owned equally by AYE and AEP, and the “Allegheny Series” which is 100% owned by AYE. The “Ohio Series” was dissolved in February 2011. Provisions exist within the PATH-WV agreement that make it a VIE. The “Ohio Series” doesdid not include the same provisions that make PATH-WV a VIE. Neither the “Ohio Series” norThe “Allegheny Series” areis not considered VIEs.a VIE. We are not required to consolidate PATH-WV as we are not the primary beneficiary, although we hold a significant variable interest in PATH-WV. Our equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets 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 should be consistent with other regulated utilities. 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. 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:
| September 30, 2010 | | December 31, 2009 | | March 31, 2011 | | December 31, 2010 |
| As Reported on | | | | | As Reported on | | | | | As Reported on | | | | | As Reported on | | | |
| the Consolidated | | Maximum | | the Consolidated | | Maximum | | the Consolidated | Maximum | the Consolidated | Maximum |
| Balance Sheet | | Exposure | | Balance Sheet | | Exposure | | Balance Sheet | Exposure | Balance Sheet | Exposure |
| | | | (in millions) | | | | | | | (in millions) | | |
Capital Contribution from AEP | | $ | 16 | | | $ | 16 | | | $ | 13 | | | $ | 13 | | $ | 19 | | $ | 19 | | $ | 18 | | $ | 18 |
Retained Earnings | | | 6 | | | | 6 | | | | 3 | | | | 3 | | | 7 | | | 7 | | | 6 | | | 6 |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total Investment in PATH-WV | | $ | 22 | | | $ | 22 | | | $ | 16 | | | $ | 16 | | $ | 26 | | $ | 26 | | $ | 24 | | $ | 24 |
Earnings Per Share (EPS)
Shown below are income statement amounts attributable to AEP common shareholders:
| | Three Months Ended | | Nine Months Ended | |
| | September 30, | | September 30, | |
Amounts Attributable to AEP Common Shareholders | | 2010 | | 2009 | | 2010 | | 2009 | |
| | (in millions) | |
Income Before Extraordinary Loss | | | $ | 555 | | | $ | 443 | | | $ | 1,035 | | | $ | 1,124 | |
Extraordinary Loss, Net of Tax | | | | - | | | | - | | | | - | | | | (5 | ) |
Net Income | | | $ | 555 | | | $ | 443 | | | $ | 1,035 | | | $ | 1,119 | |
Basic earnings per common share is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.
The following table presents our basic and diluted EPS calculations included on our Condensed Consolidated Statements of Income:
| | | Three Months Ended September 30, |
| | | 2010 | | 2009 |
| | | (in millions, except per share data) |
| | | | | | $/share | | | | | $/share |
Earnings Applicable to AEP Common Shareholders | | $ | 555 | | | | | $ | 443 | | | |
| | | | | | | | | | | | | |
Weighted Average Number of Basic Shares Outstanding | | | 479.6 | | $ | 1.16 | | | 476.9 | | $ | 0.93 |
Weighted Average Dilutive Effect of: | | | | | | | | | | | | |
| Performance Share Units | | | - | | | - | | | 0.1 | | | - |
| Stock Options | | | 0.1 | | | - | | | - | | | - |
| Restricted Stock Units | | | 0.1 | | | - | | | 0.1 | | | - |
Weighted Average Number of Diluted Shares Outstanding | | | 479.8 | | $ | 1.16 | | | 477.1 | | $ | 0.93 |
| | | | Nine Months Ended September 30, |
| | | | 2010 | | 2009 |
| | | | (in millions, except per share data) |
| | | | | | | $/share | | | | | $/share |
| Earnings Applicable to AEP Common Shareholders | | $ | 1,035 | | | | | $ | 1,119 | | | |
| | | | | | | | | | | | | | |
| Weighted Average Number of Basic Shares Outstanding | | | 479.0 | | $ | 2.16 | | | 452.3 | | $ | 2.47 |
| Weighted Average Dilutive Effect of: | | | | | | | | | | | | |
| | Performance Share Units | | | 0.1 | | | - | | | 0.2 | | | - |
| | Stock Options | | | 0.1 | | | - | | | - | | | - |
| | Restricted Stock Units | | | 0.1 | | | - | | | - | | | - |
| Weighted Average Number of Diluted Shares Outstanding | | | 479.3 | | $ | 2.16 | | | 452.5 | | $ | 2.47 |
| | | Three Months Ended March 31, |
| | | 2011 | | 2010 |
| | | (in millions, except per share data) |
| | | | | | $/share | | | | | $/share |
Earnings Applicable to AEP Common Shareholders | | $ | 353 | | | | | $ | 344 | | | |
| | | | | | | | | | | | | |
Weighted Average Number of Basic Shares Outstanding | | | 481.1 | | $ | 0.73 | | | 478.4 | | $ | 0.72 |
Weighted Average Dilutive Effect of: | | | | | | | | | | | | |
| Performance Share Units | | | - | | | - | | | 0.3 | | | - |
| Stock Options | | | 0.1 | | | - | | | - | | | - |
| Restricted Stock Units | | | 0.2 | | | - | | | 0.1 | | | - |
Weighted Average Number of Diluted Shares Outstanding | | | 481.4 | | $ | 0.73 | | | 478.8 | | $ | 0.72 |
The assumed conversion of stock options does not affect net earnings for purposes of calculating diluted earnings per share.
Options to purchase 136,250 and 612,916437,866 shares of common stock were outstanding at September 30,March 31, 2011 and 2010, and 2009, respectively, but were not included in the computation of diluted earnings per share attributable to AEP common shareholders. Since the options’ exercise prices were greater than the average market price of the common shares, the effect would have been antidilutive.
| Supplementary Information | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
| | | | | Three Months Ended | | Nine Months Ended |
| | | | | September 30, | September 30, |
| Related Party Transactions | | 2010 | | 2009 | | 2010 | | 2009 |
| | | (in millions) |
| AEP Consolidated Revenues – Utility Operations: | | | | | | | | | | | | |
| | Ohio Valley Electric Corporation (43.47% owned) | | $ | - | | $ | - | | $ | (20) | (a) | $ | - |
| AEP Consolidated Revenues – Other Revenues: | | | | | | | | | | | | |
| | Ohio Valley Electric Corporation – Barging and Other | | | | | | | | | | | | |
| | | Transportation Services (43.47% Owned) | | | 6 | | | 7 | | | 22 | | | 22 |
| AEP Consolidated Expenses – Purchased Energy for Resale: | | | | | | | | | | | | |
| | Ohio Valley Electric Corporation (43.47% Owned) | | | 66 | | | 71 | | | 223 | (b) | | 213 |
Supplementary Information | | | | | | | |
| | | | | | | | | | |
| | | | | Three Months Ended March 31, | |
Related Party Transactions | | 2011 | | 2010 | |
| | | (in millions) | |
AEP Consolidated Revenues – Utility Operations: | | | | | | | |
| Ohio Valley Electric Corporation (43.47% owned) | | $ | - | | $ | (9) | (a) |
AEP Consolidated Revenues – Other Revenues: | | | | | | | |
| Ohio Valley Electric Corporation – Barging and Other | | | | | | | |
| | Transportation Services (43.47% Owned) | | | 7 | | | 8 | |
AEP Consolidated Expenses – Purchased Electricity | | | | | | | |
| for Resale: | | | | | | | |
| Ohio Valley Electric Corporation (43.47% Owned) | | | 86 | (b) | | 77 | (c) |
| | In January 2010, theThe AEP Power Pool began purchasingpurchased power from OVEC to serve off-system sales throughin an agreement that began in January 2010 and ended in June 2010. |
| | In January 2010,March 2011, the AEP Power Pool began purchasing power from OVEC to serve retail sales through June 2011. The total amount reported includes $8 million related to this agreement. |
| | The AEP Power Pool purchased power from OVEC to serve retail sales in an agreement that began in January 2010 and ended in June 2010. The total amount reported includes $10$6 million related to this agreement. |
Adjustments to Reported Cash Flows
In the Financing Activities section of our Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2009, we corrected the presentation of borrowings on our lines of credit of $90 million from Change in Short-term Debt, Net to Borrowings from Revolving Credit Facilities. We also corrected the presentation of repayments on our lines of credit of $2.1 billion for the nine months ended September 30, 2009 to Repayments to Revolving Credit Facilities from Change in Short-term Debt, Net. The correction to present borrowings and repayments on our lines of credit on a gross basis was not material to our financial statements and had no impact on our previously reported net income, changes in shareholders' equity, financial position or net cash flows from financing activities.
Adjustments to Securitized Accounts Receivable Disclosure
In the “Securitized Accounts Receivable – AEP Credit” section of Note 11,10, we expanded our disclosure to reflect certain prior period amounts related to our securitization agreement that were not previously disclosed. These omissions were not material to our financial statements and had no impact on our previously reported net income, changes in shareholders’ equity, financial position or cash flows.
2. NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEM
NEW ACCOUNTING PRONOUNCEMENTS
Upon issuance of final pronouncements, we review the new accounting literature to determine its relevance, if any, to our business. The following represents a summary of final pronouncements that impact our financial statements.
Pronouncements Adopted During 2010
The following standards were effective during the first nine months of 2010. Consequently, their impact is reflected in the financial statements. The following paragraphs discuss their impact.
ASU 2009-16 “Transfers and Servicing” (ASU 2009-16)
In 2009, the FASB issued ASU 2009-16 clarifying when a transfer of a financial asset should be recorded as a sale. The standard defines participating interest to establish specific conditions for a sale of a portion of a financial asset. This standard must be applied to all transfers after the effective date.
We adopted ASU 2009-16 effective January 1, 2010. AEP Credit transfers an interest in receivables it acquires from certain of its affiliates to bank conduits and receives cash. As of December 31, 2009, AEP Credit owed $656 million to bank conduits related to receivable sales outstanding. Upon adoption of ASU 2009-16, future transactions do not constitute a sale of receivables and are accounted for as financings. Effective January 2010, we record the receivables and related debt on our Condensed Consolidated Balance Sheet.
ASU 2009-17 “Consolidations” (ASU 2009-17)
In 2009, the FASB issued ASU 2009-17 amending the analysis an entity must perform to determine if it has a controlling financial interest in a VIE. In addition to presentation and disclosure guidance, ASU 2009-17 provides that the primary beneficiary of a VIE must have both:
· | The power to direct the activities of the VIE that most significantly impact the VIE’s economic performance. |
· | The obligation to absorb the losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. |
We adopted the prospective provisions of ASU 2009-17 effective January 1, 2010 and deconsolidated DHLC. DHLC was deconsolidated due to the shared control between SWEPCo and CLECO. After January 1, 2010, we report DHLC using the equity method of accounting.
This standard increased our disclosure requirements for AEP Credit and Transition Funding, wholly-owned consolidated subsidiaries. See “Variable Interest Entities” section of Note 1 for further discussion.
EXTRAORDINARY ITEM
SWEPCo Texas Restructuring
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 May 2009, the governor of Texas signed a bill related to SWEPCo’s SPP area of Texas that requires continued cost of service regulation until certain stages have been completed and approved by the PUCT such that fair competition is available to all Texas retail customer classes. Based upon the signing of the bill, SWEPCo re-applied “Regulated Operations” accounting guidance for the generation portion of SWEPCo’s Texas retail jurisdiction effective second quarter of 2009. Management believes that a return to competition in the SPP area of Texas will not occur. The reapplication of “Regulated Operations” accounting guidance resulted in an $8 million ($5 million, net of tax) extraordinary loss.
3.2. RATE MATTERS
As discussed in the 20092010 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within our 20092010 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 20102011 and updates the 20092010 Annual Report.
Regulatory Assets Not Yet Being Recovered | | | | | | |
| | | | September 30, | | December 31, |
| | | | 2010 | | 2009 |
| | | | (in millions) |
| Noncurrent Regulatory Assets (excluding fuel) | | | | | | |
| Regulatory assets not yet being recovered pending future proceedings | | | | | | |
| | to determine the recovery method and timing: | | | | | | |
| Regulatory Assets Currently Earning a Return | | | | | | |
| | Customer Choice Deferrals - CSPCo, OPCo | | $ | 58 | | $ | 57 |
| | Storm Related Costs - CSPCo, OPCo, TCC | | | 52 | | | 49 |
| | Line Extension Carrying Costs - CSPCo, OPCo | | | 52 | | | 43 |
| | Acquisition of Monongahela Power - CSPCo | | | 7 | | | 10 |
| Regulatory Assets Currently Not Earning a Return | | | | | | |
| | Mountaineer Carbon Capture and Storage Project - APCo | | | 59 | | | 111 |
| | Environmental Rate Adjustment Clause - APCo | | | 48 | | | 25 |
| | Storm Related Costs - APCo, PSO, KGPCo | | | 44 | | | - |
| | Deferred Wind Power Costs - APCo | | | 24 | | | 5 |
| | Transmission Rate Adjustment Clause - APCo | | | 21 | | | 26 |
| | Special Rate Mechanism for Century Aluminum - APCo | | | 13 | | | 12 |
| | Acquisition of Monongahela Power - CSPCo | | | 4 | | | - |
| | Storm Related Costs - KPCo | | | - | (a) | | 24 |
| | Peak Demand Reduction/Energy Efficiency - CSPCo, OPCo | | | - | (a) | | 8 |
| Total Regulatory Assets Not Yet Being Recovered | | $ | 382 | | $ | 370 |
| | | | | | | | |
| (a) | Recovery of regulatory asset was granted during 2010. | | | | | | |
Regulatory Assets Not Yet Being Recovered | | | | | | |
| | | | March 31, | | December 31, |
| | | | 2011 | | 2010 |
| | | | (in millions) |
| Noncurrent Regulatory Assets (excluding fuel) | | | | | | |
| Regulatory assets not yet being recovered pending future proceedings | | | | | | |
| | to determine the recovery method and timing: | | | | | | |
| Regulatory Assets Currently Earning a Return | | | | | | |
| | Customer Choice Deferrals - CSPCo, OPCo (a) | | $ | 59 | | $ | 59 |
| | Line Extension Carrying Costs - CSPCo, OPCo (a) | | | 58 | | | 55 |
| | Storm Related Costs - CSPCo, OPCo (a) | | | 31 | | | 30 |
| | Storm Related Costs - TCC | | | 25 | | | 25 |
| | Acquisition of Monongahela Power - CSPCo (a) | | | 8 | | | 8 |
| | Other Regulatory Assets Not Yet Being Recovered | | | 7 | | | 7 |
| Regulatory Assets Currently Not Earning a Return | | | | | | |
| | Environmental Rate Adjustment Clause - APCo | | | 56 | | | 56 |
| | Storm Related Costs - APCo, KGPCo, PSO, SWEPCo | | | 45 | | | 45 |
| | Deferred Wind Power Costs - APCo | | | 34 | | | 29 |
| | Mountaineer Carbon Capture and Storage Product Validation Facility - APCo (b) | | | 19 | | | 60 |
| | Special Rate Mechanism for Century Aluminum - APCo | | | 13 | | | 13 |
| | Acquisition of Monongahela Power - CSPCo (a) | | | 4 | | | 4 |
| | Other Regulatory Assets Not Yet Being Recovered | | | 5 | | | 4 |
| Total Regulatory Assets Not Yet Being Recovered | | $ | 364 | | $ | 395 |
| | | | | | | | |
| (a) | Requested to be recovered in a distribution asset recovery rider. See the "Ohio Distribution Base Rate Case" section below. |
| (b) | APCo wrote off a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC in March 2011. See "Mountaineer Carbon Capture and Storage Project Product Validation Facility" section below. |
CSPCo and OPCo Rate Matters
Ohio Electric Security Plan Filings
2009 – 2011 ESPs
The PUCO issued an order in March 2009 that modified and approved CSPCo’s and OPCo’s ESPs which established rates at the start of the April 2009 billing cycle. The ESPs are in effect through 2011. The order also limitslimited annual rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011. Some rate components and increases are exempt from these limitations. CSPCo and OPCo collected the 2009 annualized revenue increase over the last nine months of 2009.
The order providesprovided a FAC for the three-year period of the ESP. The FAC increase will bewas phased in to avoid having the resultant rate increases exceed the ordered annual caps described above. The FAC increase is subject to quarterly true-ups, annual accounting audits and prudency reviews. See the “2009 Fuel Adjustment Clause Audit” section below. The order allowsallowed CSPCo and OPCo to defer any unrecovered FAC costs resulting from the annual caps and to accrueaccrued associated carrying charges at CSPCo’s and OPCo’s weighted average cost of capital. Any deferred FAC regulatory asset balance at the end of the three-year ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018. That recovery will include deferrals asso ciatedassociated with the Ormet interim arrangement and is subject to the PUCO’s ultimate decision regarding the Ormet interim arrangement deferrals plus related carrying charges. See the “Ormet Interim Arrangement” section below. The FAC deferralsdeferral as of September 30, 2010 were $15March 31, 2011 was $19 million and $433$498 million for CSPCo and OPCo, respectively, excluding $2 million$77 thousand and $24$37 million, respectively, of unrecognized equity carrying costs.
Discussed below are the significant outstanding uncertainties related to the ESP order:
The Ohio Consumers’ Counsel filed a notice of appeal with the Supreme Court of Ohio raising several issues including alleged retroactive ratemaking, recovery of carrying charges on certain environmental investments, Provider of Last Resort (POLR) charges and the decision not to offset rates by off-system sales margins. A decision from the Supreme Court of Ohio is pending.
In November 2009, the Industrial Energy Users-Ohio (IEU) filed a notice of appeal with the Supreme Court of Ohio challenging components of the ESP order including the POLR charge, the distribution riders for gridSMARTSM® and enhanced reliability, the PUCO’s conclusion and supporting evaluation that the modified ESPs are more favorable than the expected results of a market rate offer, the unbundling of the fuel and non-fuel generation rate components, the scope and design of the fuel adjustment clause and the approval of the plan after the 150-day statutory deadline. A decision from
In April 2011, the Supreme Court of Ohio (the Court) issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged which resulted in three reversals, only two of which may have a prospective impact. First, the Court concluded that the PUCO's decision amounted to retroactive ratemaking. Since the pertinent revenues were collected in 2009 and the OCC did not successfully pursue the remedy of obtaining a stay of the order prior to the revenues being collected, there is pending.no remand to the PUCO or refund to customers for this error. Second, the Court held that the PUCO's conclusion that the POLR charge is cost-based conflicted with the evidence and remanded the issue to the PUCO for further consideration. Third, the Court reversed the Order’s legal basis for a carrying charge associated with certain environmental investments and remanded that issue to the PUCO to determine whether an alternative legal basis supports the charge. If any rate changes result from the PUCO’s remand proceedings, such rate changes would be prospective from the date of the remand order through the remaining months of 2011.
In April 2010, the Industrial Energy Users-OhioIEU filed an additional notice of appeal with the Supreme Court of Ohio challenging alleged retroactive ratemaking, CSPCo's and OPCo's abilities to collect through the FAC amounts deferred under the Ormet interim arrangement and the approval of the plan after the 150-day statutory deadline. A decision from the Supreme Court of Ohio is pending.
In 2009, the PUCO convened a workshop to determine the methodology for the Significantly Excessive Earnings Test (SEET). Ohio law requires that the PUCO determine, following the end of each year of the ESP, if rate adjustments included in the ESP resulted in significantly excessive earnings. If the rate adjustments, in the aggregate, result in significantly excessive earnings, the excess amount could be returned to customers. The PUCO heard arguments related to various SEET issues including the treatment of the FAC deferrals. Management believes that CSPCo and OPCo should not be required to refund unrecovered FAC regulatory assets until they are collected, even assuming there are significantly excessive earnings in that year. In June 2010,January 2011, the PUCO issued an order re solving someon CSPCo’s and OPCo’s 2009 SEET filings and determined that OPCo’s 2009 earnings were not significantly excessive but determined relevant CSPCo earnings exceeded the PUCO determined threshold by 2.13%. As a result, the PUCO ordered CSPCo to refund $43 million ($28 million net of tax) of its earnings to customers, which was recorded as a revenue provision on CSPCo’s December 2010 books. The PUCO ordered that the significantly excessive earnings be applied first to CSPCo’s FAC deferral, including unrecognized equity carrying costs, as of the SEET issues. The PUCO determined thatdate of the earnings of CSPCo and OPCo shallorder, with any remaining balance to be calculated on an individual company basis and notcredited to CSPCo’s customers on a combined CSPCo/OPCoper kilowatt basis. The PUCO ruled that many issues,That credit began with the first billing cycle in February 2011 and will continue through December 2011. Several parties, including the treatment of deferrals and off-system sales, should be determined on a case-by-case basis. The PUCO’s decision on the SEET methodology is not expected to be finalized until after the PUCO issues an order on the SEET filings. In September 2010, CSPCo and OPCo, filed requests for rehearing with the PUCO, which were denied in March 2011. CSPCo and OPCo are required to file their 20092010 SEET filings with the PUCO. CSPCo’s and OPCo’s returns on common equity were 20.84% and 10.81%, respectively, including off-system sales margins and 18.31% and 9.42%, respectively, excluding off-system sales margins. IncludedPUCO in the filings was CSPCo’s and OPCo’s determination that the level at which their earned return on common eq uity may become significantly in excess of the average earned return on common equity of the comparable risk group of publicly traded firms was 22.51%.2011. Based upon the methodology proposed by CSPCo and OPCoapproach in the SEET filings, neither CSPCo’s nor OPCo’sPUCO 2009 return on common equity was significantly excessive. In October 2010, the PUCO staff filed testimonyorder, management does not currently believe that recommended a return on common equity over 16.05% asCSPCo or OPCo will have any significantly excessive but did not address whether adjustments for off-system sales (OSS) and deferrals should be made to reduce the return. Also,earnings in October 2010, intervenors, including the Ohio Consumers’ Counsel, filed testimony with the PUCO recommending an acceptable return on common equity in the range of 11.58% to 13.58%. As a result, t he intervenors recommended CSPCo refund up to $156 million of its 2009 earnings. If the PUCO determines that CSPCo’s and/or OPCo’s 2009 return on common equity was significantly excessive, CSPCo and/or OPCo may be required to return a portion of their ESP revenues to customers.2010.
Management is unable to predict the outcome of the various ongoing ESP proceedings and litigation discussed above. If these proceedings, including future SEET filings, result in adverse rulings, it could reduce future net income and cash flows and impact financial condition.
January 2012 – May 2014 ESP
In January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing on a combined company basis for generation. The rates would be effective with the first billing cycle of January 2012 through the last billing cycle of May 2014. The ESP also includes alternative energy resource requirements and addresses provisions regarding distribution service, energy efficiency
requirements, economic development, job retention in Ohio and other matters. The SSO presents redesigned generation rates by customer class. Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013. The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESP could impact the outcome of the January 2012 – May 2014 ESP, though the nature and extent of that impact is not presently known.
Ohio Distribution Base Rate Case
In February 2011, CSPCo and OPCo filed with the PUCO for an annual increase in distribution rates of $34 million and $60 million, respectively. The requested increase is based upon an 11.15% return on common equity to be effective January 2012.
In addition to the annual increase, CSPCo and OPCo requested recovery of the projected December 31, 2012 balance of certain distribution regulatory assets of $216 million and $159 million, respectively, including approximately $102 million and $84 million, respectively, of unrecognized equity carrying costs. These assets would be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013. The actual balance of these distribution regulatory assets as of March 31, 2011 was $98 million and $63 million for CSPCo and OPCo, respectively, excluding $57 million and $42 million of unrecognized equity carrying costs, respectively. If CSPCo and OPCo are not ultimately permitted to fully recover their deferrals, it would reduce future net income and cash flows and impact financial condition.
Proposed CSPCo and OPCo Merger
In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo. Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company. The merger is also subject to regulatory approval by the FERC.In January 2011, CSPCo and OPCo anticipate completionfiled an application with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo. CSPCo and OPCo requested the reorganization transaction be effective in October 2011. Decisions are pending from the PUCO and the FERC. Management is unable to predict the outcome of the merger during 2011.this proceeding.
Requested Sporn Unit 5 Shutdown and Proposed Distribution Rider
In October 2010, OPCo filed an application with the PUCO for the approval of a December 2010 closure of Sporn Unit 5 and the simultaneous establishment of a new non-bypassable distribution rider, outside the rate caps established in the 2009 – 2011 ESP proceeding. The proposed rider would recover the net book value of the unit as well as related materials and supplies as of December 2010, which iswas estimated to be $59 million, as well as future closure costs incurred after December 2010. OPCo also requested the PUCO to grant accounting authority to record the future closure costs as a regulatory asset or regulatory liability with a weighted average cost of capital carrying charge to be included in the proposed non-bypassable distribution rider after theythe costs are incurred. A lso in October 2010, OPCo filed a retirement notification with PJM pendingPending PUCO approval, of OPCo’s application to close Sporn Unit 5. Absent PUCO approval, management intends to operate Sporn Unit 5 through 2013.continues to operate. In April 2011, intervenors filed comments opposing OPCo’s application. A PUCO decision is pending as to whether a hearing will be ordered. Management is unable to predict the outcome of this proceeding.
2009 Fuel Adjustment Clause Audit
As required under the ESP orders, the PUCO selected an outside consultant to conduct the audit of the FAC for the period of January 2009 through December 2009. In May 2010, the outside consultant provided theirits confidential audit report of the FAC audit to the PUCO. The audit report included a recommendation that the PUCO should review whether any proceeds from a 2008 coal contract settlement agreement which totaled $72 million should reduce OPCo’s FAC under-recovery balance. Of the total proceeds, approximately $58 million was recognized as a reduction to fuel expense prior to 2009 and $14 million will reducewas recognized as a reduction to fuel expense in 2009 and 2010. Hearings were held in August 2010. Management is unable to predict the outcome of this proceeding. If the PUCO orders any portion of the $58 million previo uslypreviously recognized gains or potential otherany future adjustments be used to reduce the current year FAC deferral, it would reduce future net income and cash flows and impact financial condition.
Ormet Interim Arrangement
CSPCo, OPCo and Ormet, a large aluminum company, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet. This interim arrangement was approved by the PUCO and was effective from January 2009 through September 2009. In March 2009, the PUCO approved a FAC in the ESP filings.filings and the FAC aspect of the ESP order was upheld by the Supreme Court’s April 2011 decision referenced in the “2009-2011 ESPs” section above. The approval of the FAC as part of the ESP, together with the PUCO approval of the interim arrangement, provided the basis to record regulatory assets for the difference between the approved market price and the rate paid by Ormet. Through September 2009, the last month of the interim arrangement, CSPCo and OPCo had $30 million and $34 million, respectively, of deferred FAC related to the interim arrangement including recog nizedrecognized carrying charges but excludingcharges. These amounts exclude $1 million and $1 million, respectively, of unrecognized equity carrying costs. In November 2009, CSPCo and OPCo requested that the PUCO approve recovery of the deferrals under the interim agreement plus a weighted average cost of capital carrying charge. The interim arrangement deferrals are included in CSPCo’s and OPCo’s FAC phase-in deferral balances. See “Ohio Electric Security Plan Filings” section above. In the ESP proceeding, intervenors requested that CSPCo and OPCo be required to refund the Ormet-related regulatory assets and requested that the PUCO prevent CSPCo and OPCo from collecting the Ormet-related revenues in the future. The PUCO did not take any action on this request in the 2009-2011 ESP proceeding. The intervenors raised the issue again in response to CSPCo’s and OPCo’s November 2009 filing to approve recovery of the deferrals under the interim agreement.agreement and this issue remains pending before the PUCO. If CSPCo and OPCo are not ultimately permitted to fully recover their requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.
Economic Development Rider
In April 2010, the Industrial Energy Users-OhioIEU filed a notice of appeal of the 2009 PUCO-approved Economic Development Rider (EDR) with the Supreme Court of Ohio. The EDR collects from ratepayers the difference between the standard tariff and lower contract billings to qualifying industrial customers, subject to PUCO approval. The Industrial Energy Users-OhioIEU raised several issues including claims that (a) the PUCO lost jurisdiction over CSPCo’s and OPCo’s ESP proceedings and related proceedings when the PUCO failed to issue ESP orders within the 150-day statutory deadline, (b) the EDR should not be exempt from the ESP annual rate limitations and (c) CSPCo and OPCo should not be allowed to apply a weighted average long-term debt carrying cost on deferred EDR regulatory assets. A decision from the Supreme Court of Ohio is pending.
In June 2010, Industrial Energy Users-Ohiothe IEU filed a notice of appeal of the 2010 PUCO-approved EDR with the Supreme Court of Ohio. The Industrial Energy Users-Ohio raisedOhio raising the same issues as noted in the 2009 EDR appeal plusappeal. In addition, the IEU added a claim that CSPCo and OPCo should not be able to take the benefits of the higher ESP rates while simultaneously challenging the ESP orders. A decision from the Supreme Court of Ohio is pending.
As of September 30, 2010,March 31, 2011, CSPCo and OPCo have incurred $39EDR costs of $48 million and $30$40 million, respectively, in EDR costs including carrying costs. Of these costs, CSPCo and OPCo have collected $2743 million and $20$33 million, respectively, through the EDR, which CSPCo and OPCo began collecting in January 2010. The remaining $12$5 million and $10$7 million for CSPCo and OPCo, respectively, are recorded as deferred EDR regulatory assets. If CSPCo and OPCo are not ultimately permitted to recover their deferrals or are required to refund EDR revenue collected, it would reduce future net income and cash flows and impact financial condition.
Environmental Investment Carrying Cost Rider
In February 2010, CSPCo and OPCo filed an application with the PUCO to establish an Environmental Investment Carrying Cost Rider to recover carrying costs for 2009 through 2011 related to environmental investments made in 2009. The carrying costs include both a return of and on the environmental investments as well as related administrative and general expenses and taxes. In August 2010, the PUCO issued an order approving a rider of approximately $26 million and $34 million for CSPCo and OPCo, respectively, effective September 2010. The implementation of the rider will likely not impact cash flows, but will increase the ESP phase-in plan deferrals associated with the FAC since this rider is subject to the rate increase caps authorized by the PUCO in the ESP proceedings.Ohio IGCC Plant
In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. Through September 30, 2010,March 31, 2011, CSPCo and OPCo have each collected $12 million in pre-construction costs authorized in a June 2006 PUCO order and each 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 before June 2011, allany pre-construction costs that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest. 160; Intervenors have filed motions with the PUCO requesting all pre-construction costs be refunded to Ohio ratepayers with interest.
CSPCo and OPCo will not start construction of an IGCC plant until existing statutory barriers are addressed and sufficient assurance of regulatory cost recovery exists. Management cannot predict the outcome of any cost recovery litigation concerning the Ohio IGCC plant or what effect, if any, such litigation would have on future net income and cash flows. However, if CSPCo and OPCo were required to refund all or some of the pre-construction costs collected and the costs incurred were not recoverable in another jurisdiction, it would reduce future net income and cash flows and impact financial condition.
SWEPCo Rate Matters
Turk Plant
SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in service in 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility. The Turk Plant is currently estimated to cost $1.7 billion, excluding AFUDC, plus an additional $132125 million for transmission, excluding AFUDC. SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $132$125 million for transmission, excluding AFUDC. As of September 30, 2010,March 31, 2011, excluding costs attributable to its joint owners, SWEPCo has capitalized approximately $957 million$1.1 billion of expenditures (includin g(including AFUDC and capitalized interest of $121$156 million and related transmission costs of $58$73 million). As of September 30, 2010,March 31, 2011, the joint owners and SWEPCo have contractual construction commitments of approximately $339$260 million (including related transmission costs of $5$3 million). SWEPCo’s share of the contractual construction commitments is $249$191 million. If the plant is cancelled, the joint owners and SWEPCo would incur contractual construction cancellation fees, based on construction status as of September 30, 2010,March 31, 2011, of approximately $121$101 million (including related transmission cancellation fees of $1 million). SWEPCo’s share of the contractual construction cancellation fees would be approximately $89$74 million.
Discussed below are the significant outstanding uncertainties related to the Turk Plant:
The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the 88 MW SWEPCo Arkansas jurisdictional share of the Turk Plant. Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN. The Arkansas Supreme Court ultimately concluded that the APSC erred in determining the need for additional power supply resources in a proceeding separate from the proceeding in which the APSC granted the CECPN. However, the Arkansas Supreme Court approved the APSC’s procedure of granting CECPNs for transmission facilities in dockets separate from the Turk Plant CECPN proceeding. In June 2010, the Arkansas Supreme Court denied motions for rehearing filed by the APSC and SWEPCo. Therefore, SWEPCo filed a notice with the APSC of its intent to proceed with construction of the Turk Plant but that SWEPCo no longer intends to pursue a CECPN to seek recovery of the originally approved 88 MW portion of Turk Plant costs in Arkansas retail rates. In June 2010, the APSC issued an order which reversed and set aside the previously granted CECPN.
The PUCT issued an order approving a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected construction cost, excluding AFUDC and related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers. SWEPCo appealed the PUCT’s order contending the two cost cap restrictions are unlawful. The Texas Industrial Energy Consumers filed an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant should be revoked because it was unnecessary to serve retail customers. In February 2010, the Texas District Court affirmed the PUCT’s order in all respects. In March 2010, SWEPCo and the Texas Industrial Energy Consumers appealed this decision to the Texas Court of Appeals. Management is unable to predict the timing of the outcome related to this proceeding.
The LPSC approved SWEPCo’s application to construct the Turk Plant. The Sierra Club petitioned the LPSC to begin an investigation into the construction of the Turk Plant which was rejected by the LPSC. The Sierra Club later refiled its petition as a stand alone complaint proceeding. SWEPCo filed a motion to dismiss and denied the allegations in the complaint. In October 2010, an Administrative Law Judge recommended the LPSC dismiss the complaint.
In November 2008, SWEPCo received its required air permit approval from the Arkansas Department of Environmental Quality and commenced construction at the site. The Arkansas Pollution Control and Ecology Commission (APCEC) upheld the air permit. In February 2010, theThe parties who unsuccessfully appealed the air permit to the APCEC filed a notice of appeal with the Circuit Court of Hempstead County, Arkansas. In December 2010, the Circuit Court affirmed the APCEC. In January 2011, the same parties filed a notice of appeal with the Arkansas Court of Appeals. A decision in that case is not likely before the third quarter of 2011.
A wetlands permit was issued by the U.S. Army Corps of Engineers in December 2009. In February 2010, the Sierra Club, the Audubon Society and others filed a complaint in the Federal District Court for the Western District of Arkansas against the U.S. Army Corps of Engineers challenging the process used and the terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts. In May 2010, plaintiffs filed with the Federal District Court for the Western District of Arkansas seekingimpacts, and sought a preliminary injunction to halt construction and for a temporary restraining order.
In July 2010, the Hempstead County Hunting Club also filed a complaint with the Federal District Court for the Western District of Arkansas against SWEPCo, the U.S. Army Corps of Engineers, the U.S. Department of the Interior and the U.S. Fish and Wildlife Service seeking a temporary restraining order and preliminary injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws. The plaintiffs’ federal law claims challenge the process used and terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts. The plaintiffs’ state law claims challenge SWEPCo's ability to construct the Turk Plant without obtaining a certificate from the APSC. This motion for pre liminary injunction was heard simultaneously with the motion filed by the Sierra Club. In October 2010, the motions for preliminary injunction were partially granted. According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop. Mitigation measures required by the permit are authorized and may be completed. The preliminary injunction affects portions of the water intake and associated piping and portions of thetwo transmission lines. A hearing on SWEPCo’s appeal was held in March 2011. Management is unable to predict the timing of the outcome related to this proceeding. In October 2010, the Federal District Court certified issues relating to the state law claims to the Arkansas Supreme Court, including whether those claims are within the primary jurisdiction of the APSC. The Arkansas Supreme Court has yet to consideraccepted the request. In April 2011, legislation was passed in Arkansas that clarifies the scope of the certificate exemption and the APSC’s primary jurisdiction over the state law claims asserted in federal court. In response to the legislation, SWEPCo filed a notice of appeal withhas requested the Federal District Court of Appeals forto withdraw the Eighth Circuit and is seeking a stay of the preliminary injunction pending appeal.
In January 2009, SWEPCo was granted CECPNs by the APSC to build three transmission lines and facilities authorized by the SPP and needed to transmit power from the Turk Plant. Intervenors appealed the CECPN decisions in April 2009questions certified to the Arkansas Supreme Court of Appeals. In July 2010,and dismiss the Hempstead County Hunting Club and other appellants filed with the Arkansas Court of Appeals emergency motions to stay the transmission CECPNs to prohibit SWEPCo from taking ownership of private property and undertaking construction of the transmission lines. In July 2010, the Arkansas Court of Appeals issued a decision remanding all transmission line CECPN appeals to the APSC. As a result, a stay was not ordered and construction continues on the affected transmission lines. A hearing is scheduled for January 2011.state law claims.
Management expects that SWEPCo will ultimately be able to complete construction of the Turk Plant and related transmission facilities and place those facilities in service. However, if SWEPCo is unable to complete the Turk Plant construction, including the related transmission facilities, and place the Turk Plant in service or if SWEPCo cannot recover all of its investment in and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.
Stall Unit
SWEPCo constructed the Stall Unit, an intermediate load 500 MW natural gas-fired combustion turbine combined cycle generating unit, at its existing Arsenal Hill Plant located in Shreveport, Louisiana. The LPSC and the APSC issued orders capping SWEPCo’s Stall Unit construction costs at $445 million including AFUDC and excluding related transmission costs. The Stall Unit was placed in service in June 2010. As of September 30, 2010, the Stall Unit cost $423 million, including $49 million of AFUDC. Management does not expect the final costs of the Stall Unit to exceed the ordered cap. In July 2010, the Stall Unit was placed into Arkansas rates. SWEPCo received CWIP treatment for a portion of the Stall Unit in the 2009 Tex as Base Rate Filing. See “2009 Texas Base Rate Filing” section below. The Stall Unit will be phased into Louisiana rate base between October 2010 and October 2011.
2009 Texas Base Rate Filing
In August 2009, SWEPCo filed a rate case with the PUCT to increase its base rates by approximately $75 million annually including a return on common equity of 11.5%. The filing included requests for financing cost riders of $32 million related to construction of the Stall Unit and Turk Plant, a vegetation management rider of $16 million and other requested increases of $27 million. In April 2010, a settlement agreement was approved by the PUCT to increase SWEPCo’s base rates by approximately $15 million annually, effective May 2010, including a return on common equity of 10.33%, which consists of $5 million related to construction of the Stall Unit and $10 million in other increases. In addition, the settlement agreement will decrease annual depreciation expense by $17 million and allows SWEPCo a $10 million one-year surcharge rider to recover additional vegetation management costs that SWEPCo must spend within two years.
Texas Fuel Reconciliation
In May 2010, various intervenors, including the PUCT staff, filed testimony recommending disallowances ranging from $3 million to $30 million in SWEPCo’s $755 million fuel and purchase power costs reconciliation for the period January 2006 through March 2009. In July 2010, Cities Advocating Reasonable Deregulation filed testimony regarding the 2007 transfer of ERCOT trading contracts to AEPEP. Included in this testimony were unquantified refund recommendations relating to re-pricing of contract transactions.
In September 2010, the Administrative Law Judges issued a Proposal for Decision (PFD) that recommended a disallowance of a significant portion of the charges to a ten-year gas transportation agreement that began in 2009 for the Mattison Plant located in Northwest Arkansas. The PFD stated that SWEPCo should have pursued other transportation options or sought the supplier’s recourse rate from the FERC. The estimated recommended disallowance over the ten-year period through December 2018 is $107 million for which the estimated Texas jurisdictional portion is $37 million. In addition, the PFD also contained recommendations to disallow risk premiums related to the ERCOT trading contracts transferred to AEPEP which are estimated to be $1.5 million on a Texa s retail jurisdictional basis. Through September 30, 2010, SWEPCo’s management estimated the impact of this PFD, if adopted by the PUCT, to be $7 million. In October 2010, SWEPCo filed exceptions on these issues with the PUCT. An order may be issued in the fourth quarter of 2010. Management is unable to predict the outcome of this reconciliation. If the PUCT disallows any portion of SWEPCo’s fuel and purchase power costs, it could reduce future net income and cash flows and possibly impact financial condition.TCC and TNC Rate Matters
TEXAS RESTRUCTURING
Texas Restructuring Appeals
Pursuant to PUCT restructuring orders, TCC securitized net recoverable stranded generation costs of $2.5 billion and is recovering the principal and interest on the securitization bonds through the end of 2020. TCC also refunded other net true-up regulatory liabilities of $375 million during the period October 2006 through June 2008 via a CTC credit rate rider under PUCT restructuring orders. TCC and intervenors appealed the PUCT’s true-up related orders. After rulings from the Texas District Court and the Texas Court of Appeals, TCC, the PUCT and intervenors filed petitions for review with the Texas Supreme Court.Court of Texas. Review is discretionary and the Texas Supreme Court of Texas has not yet determined if it will grant review. The Texas Supreme Court of Texas requested a full briefing which has c oncluded.concluded. The following represent issues where either the Texas District Court or the Texas Court of Appeals recommended the PUCT decision be modified:
· | The Texas District Court judge determined that the PUCT erred by applying an invalid rule to determine the carrying cost rate for the true-up of stranded costs. The Texas Court of Appeals reversed the District Court’s unfavorable decision. An October 2010 decision of the Texas Supreme Court of Texas addressing the same issue for another utility upholds the Court of Appeals determination. |
· | The Texas District Court judge determined that the PUCT improperly reduced TCC’s net stranded plant costs for commercial unreasonableness. This favorable decision was affirmed by the Texas Court of Appeals. |
· | The Texas Court of Appeals determined that the PUCT erred by not reducing stranded costs by the “excess earnings” that had already been refunded to affiliated Retail Electric Providers (REPs). ThisA March 2011 decision by the Supreme Court of Texas addressing the same issue for another utility overturned the Texas |
| Court of Appeals decision. If the Supreme Court of Texas does not overturn TCC’s Texas Court of Appeals decision, it could be unfavorable unless the PUCT allows TCC to recover the refunds previously made to the REPs. See the “TCC Excess Earnings” section below. |
Management cannot predict the outcome of the pending court proceedings and the PUCT remand decisions. If TCC ultimately succeeds in its appeals, it could have a favorable effect on future net income, cash flows and possibly financial condition. If intervenors succeed in their appeals, it could reduce future net income and cash flows and possibly impact financial condition.
TCC Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes
In 2006, the PUCT reduced recovery of the amount securitized by $103 million of tax benefits and associated carrying costs related to TCC’s generation assets. In 2006, TCC obtained a private letter ruling from the IRS which confirmed that such reduction was an IRS normalization violation. In order to avoid a normalization violation, the PUCT agreed to allow TCC to defer refunding the tax benefits of $103 million plus interest through the CTC refund period pending resolution of the normalization issue. In 2008, the IRS issued final regulations, which supported the IRS’IRS’s private letter ruling which would make the refunding of or the reduction of the amount securitized by such tax benefits a normalization violation. After the IRS issued i tsits final regulations, at the request of the PUCT, the Texas Court of Appeals remanded the tax normalization issue to the PUCT for the consideration of additional evidence including the IRS regulations. TCC is not accruing interest on the $103 million because it is not probable that the PUCT will order TCC to violate the normalization provision of the Internal Revenue Code. If interest were accrued, management estimates interest expense would have been approximately $2025 million higher for the period July 2008 through September 2010.March 2011. Management believes that the PUCT will ultimately allow TCC to retain the deferred amounts, which would have a favorable effect on future net income and cash flows. Although unexpected, if the PUCT fails to issue a favorable order and orders TCC to return the tax benefits to customers, the resulting normalization violation could result in TCC’s repayment to the IRS of Accumulated Deferred Investment Tax Credits (ADITC) on all property, including transmission and distribution property. This amount approximates $101 million as of September 30, 2010.March 31, 2011. It could also lead to a loss of TCC’s right to claim accelerated tax depreciation in future tax returns. If TCC is required to repay its ADITC to the IRS and is also required to refund ADITC plus unaccrued interest to customers, it wou ldwould reduce future net income and cash flows and impact 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 Retail Electric Providers (REPs)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 costs in the true-up proceeding.
Certain parties have taken positions that, if adopted, could result in TCC being required to refund excess earnings and interest through the true-up process without receiving a refund from the REPs. If this were to occur, it would reduce future net income and cash flows and impact financial condition. Management cannot predictA March 2011 decision by the outcomeSupreme Court of Texas addressing the excess earnings remand.
OTHER TEXAS RATE MATTERS
Texas Base Rate Appeal
TCC filed a base rate case in 2006 seeking to increase base rates. The PUCT issued an order in 2007 which increased TCC’s base rates by $20 million, eliminated a merger credit rider of $20 million and reduced depreciation rates by $7 million. The PUCT decision was appealed by TCC and various intervenors. On appeal, the Texas District Court affirmed the PUCT in most respects. Various intervenors appealed that decision. In June 2010,same issue for another utility overturned the Texas Court of Appeals affirmed the Texas District Court’s decision. The order became final with an August 2010 Texas Court of Appeals mandate.
ETT 2007 Formation Appeal
ETT is a joint venture between AEP Utilities, Inc. and MidAmerican Energy Holdings Company Texas Transco, LLC. TCC and TNC have sold transmission assets both in service and under construction to ETT. The PUCT approved ETT's initial rates, a request for a transfer of in-service assets and CWIP and a certificate of convenience and necessity (CCN) to operate as a stand alone transmission utility in ERCOT. ETT was allowed a 9.96% return on common equity. Intervenors appealed the PUCT’s decision. In March 2010, the Texas Court of Appeals affirmed the PUCT's decision in all material respects. Intervenors filed for rehearing at the Texas Court of Appeals which was denied in May 2010. The deadline to appeal this decision to the Texas Supreme Court has expired.
In a separate development, the Texas governor signed a new law that clarifies the PUCT’s authority to grant CCNs to transmission only utilities such as ETT. ETT filed an application with the PUCT for a CCN under the new law. In March 2010, the PUCT approved the application for a CCN under the new law.
APCo and WPCo Rate Matters
2009 Virginia Biennial Base Rate Case
In July 2009,March 2011, APCo filed a generation and distribution base rate increaserequest with the Virginia SCC to increase annual base rates by $126 million based upon an 11.65% return on common equity to be effective no later than February 2012. The return on common equity includes a requested 0.5% renewable portfolio standards incentive as allowed by law. APCo proposed to mitigate the requested base rate increase by $51 million by maintaining current depreciation rates until the next biennial filing. If approved, APCo’s net base rate increase would be $75 million.
Rate Adjustment Clauses
In 2007, the Virginia law governing the regulation of $154electric utility service was amended to, among other items, provide for rate adjustment clauses (RACs) beginning in January 2009 for the timely and current recovery of costs of (a) transmission services billed by an RTO, (b) demand side management and energy efficiency programs, (c) renewable energy programs, (d) environmental compliance projects and (e) new generation facilities, including major unit modifications. In March 2011, APCo filed for approval of an environmental RAC, a renewable energy program RAC and a generation RAC simultaneous with the 2011 Virginia base rate filing. The environmental RAC is requesting recovery of environmental compliance costs incurred from January 2009 through December 2010 of $38 million annually based on a 13.35% return on common equity. Interim rates, subjecttwo-year amortization. The renewable energy program RAC is requesting the incremental portion of deferred wind power costs for the Camp Grove and Fowler Ridge projects of $6 million. The generation RAC is requesting recovery of the Dresden Plant, currently under construction, which APCo has requested to refund, became effectivepurchase from AEGCo.
In accordance with Virginia law, APCo is deferring incremental environmental costs incurred after December 2008 and renewable energy costs incurred after August 2009 which are not being recovered in December 2009 but were discontinuedcurrent revenues. As of March 31, 2011, APCo has deferred $56 million of environmental costs (excluding $12 million of unrecognized equity carrying costs) and $34 million of renewable energy costs. APCo plans to seek recovery of non-incremental deferred wind power costs ($28 million as of March 31, 2011) in February 2010 when newly enacted Virginia legislation suspended the collection of interim rates. In July 2010,future rate proceedings. If the Virginia SCC issued an order approvingwere to disallow a $62 million increase based on a 10.53% return on common equity. The order denied recoveryportion of the Virginia share of the Mountaineer Carbon CaptureAPCo’s deferred costs, it would reduce future net income and Storage Project, which resulted in a pretax write-off of $54 million in the second quarter of 2010. See “Mountaineer Carbon Capture and Storag e Project” section below. In addition, the order allowed the deferral of approximately $25 million of incremental storm expense incurred in 2009. In July 2010, APCo filed with the Virginia SCC a petition for reconsideration of the order as it relates to the Mountaineer Carbon Capture and Storage Project which was denied in August 2010. Approximately $3 million, including interest, was refunded to customers in September 2010 related to the collection of interim rates.cash flows.
2010 West Virginia Base Rate Case
In May 2010, APCo and WPCo filed a request with the WVPSC to increase annual base rates by $156 million based on an 11.75% return on common equity to be effective March 2011. Hearings are scheduled for December 2010. A decision fromIn March 2011, the WVPSC is expectedmodified and approved a settlement agreement which increased annual base rates by approximately $51 million based upon a 10% return on common equity. The settlement agreement also resulted in Marcha pretax write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility in the first quarter of 2011. See “Mountaineer Carbon Capture and Storage Project Product Validation Facility” section below. In addition, the WVPSC allowed APCo to defer and amortize $18 million of previously expensed 2009 incremental storm expenses and allowed APCo and WPCo to defer and amortize $15 million of costs that were previously expensed related to the 2010 cost reduction initiative, each over a period of seven years.
Mountaineer Carbon Capture and Storage Project
Product Validation Facility (PVF)
APCo and ALSTOM Power, Inc., an unrelated third party, jointly constructed a CO2 capture validation facility, which was placed into service in September 2009. APCo also constructed and owns the necessary facilities to store the CO2. In October 2009, APCo started injecting CO2 into the underground storage facilities. The injection of CO2 required the recording of an asset retirement obligation and an offsetting regulatory asset. Through September 30, 2010, APCo has recorded a noncurrent regulatory ass et of $59 million related to the Mountaineer Carbon Capture and Storage Project.
In APCo’s July 2009and WPCo’s May 2010 West Virginia base rate filing, APCo and WPCo requested recoveryrate base treatment of and a return on its Virginia jurisdictional share of its project costs andthe PVF, including recovery of the related asset retirement obligation regulatory asset amortization and accretion. In July 2010,March 2011, a WVPSC order denied the Virginia SCC issued arequest for rate base treatment of the PVF largely due to its experimental operation. The base rate order provided that denied recoveryshould APCo construct a commercial scale carbon capture and sequestration (CCS) facility, only the West Virginia portion of the Virginia sharePVF costs, based on load sharing among certain AEP operating companies, may be considered used and useful plant in service and included in future rate base. As a result, APCo recorded a pretax write-off of $41 million ($26 million net of tax) in the Mountaineer Carbon Capture and Storage Project costs.first quarter of 2011. See “2009“2010 West Virginia Base Rate Case” section above.
In APCo’s May 2010 West Virginia base rate filing, As of March 31, 2011, APCo
requested recovery of andhas recorded a
return on its West Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligationnoncurrent regulatory asset
amortization and accretion.of $19 million related to the PVF. If APCo cannot recover its remaining investment in and
accretion expenses related to the
Mountaineer PVF, it would reduce future net income and cash flows.
Carbon Capture and StorageSequestration Project with the Department of Energy (DOE)
During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale CCS facility under consideration at the Mountaineer Plant. AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project. The DOE will fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million. A Front-End Engineering and Design (FEED) study, scheduled for completion during the third quarter of 2011, will refine the total cost estimate for the CCS facility. Results from the FEED study will be evaluated by management before any decision is made to seek the necessary regulatory approvals to build the CCS facility. As of March 31, 2011, APCo has incurred $25 million in total costs and has received $7 million of DOE eligible funding resulting in a net $18 million balance included in Construction Work In Progress on the Condensed Consolidated Balance Sheets. If APCo is unable to recover the costs of the CCS project, it would reduce future net income and cash flows and impact financial condition.flows.
APCo’s Filings for an IGCC Plant
APCo filed a petition with the WVPSC requesting approval of a Certificate of Public Convenience and Necessity (CPCN) to construct a 629 MW IGCC power plant in Mason County, West Virginia. APCo also requestedIn 2008, the Virginia SCC and the WVPSC to approveissued an order denying APCo’s request for a surcharge rate mechanism to provide for the timely recovery of pre-construction costs and the ongoing financing costs of the project during the construction period, as well as the capital costs, operating costs and a return on common equity once the facility is placed into commercial operation. The WVPSC granted APCo the CPCN and approved the requested cost recovery. Various intervenors filed petitions with the WVPSC to reconsider the order.
In 2008,order was based upon the Virginia SCC issued an order denying APCo’s request for a surcharge rate mechanism based upon itsSCC's finding that the estimated cost of the plant was uncertain and may escalate. The Virginia SCC also expressed concerns that the estimated costs did not include a retrofitting of carbon capture and sequestrationCCS facilities. During 2009, based on an unfavorablethe order received in Virginia, the WVPSC removed the IGCC case as an active case from its docket and indicated that the conditional CPCNCertificate of Environmental Compatibility and Public Need granted in 2008 must be reconsidered if and when APCo proceeds forward with the IGCC plant.
Through September 30, 2010,March 31, 2011, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $9$9 million applicable to its Virginia jurisdiction.
APCo will not start construction of the IGCC plant until sufficient assurance of full cost recovery exists in Virginia and in West Virginia. If the plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs. If the costs which, ifare not recoverable, it would reduce future net income and cash flows and impact financial condition.
APCo’s and WPCo’s 2009 Expanded Net Energy Charge (ENEC) Filing
In September 2009, the WVPSC issued an order approving APCo’s and WPCo’s March 2009 ENEC request. The approved order provided for recovery of an under-recovered balance plus a projected increase in ENEC costs over a four-year phase-in period with an overall increase of $355 million and a first-year increase of $124 million, effective October 2009. The WVPSC also approved a fixed annual carrying cost rate of 4%, effective October 2009, to be applied to the incremental deferred regulatory asset balance that will result from the phase-in plan and lowered annual coal cost projections by $27 million. As of September 30, 2010, APCo’s ENEC under-recovery balance was $365 million, excluding $1 million o f unrecognized equity carrying costs, which is included in noncurrent regulatory assets.
In June 2010, the WVPSC approved a settlement agreement for $96 million, including $10 million of construction surcharges was filed with the WVPSC related to APCo’s and WPCo’s second year ENEC increase. The settlement agreement provided for recovery of the amounts related to the renegotiated coal contracts and allows APCo to accrue a weighted average cost of a capital carrying costscharge on the excess under-recovery balance due to the ENEC phase-in as adjusted for the impacts of Accumulated Deferred Income Taxes. In June 2010, the WVPSC approved the settlement agreement which madeThe new rates became effective in July 2010.
PSO Rate Matters
PSO FuelIn March 2011, APCo and Purchased Power
2006WPCo filed their third year ENEC increase with the WVPSC to increase rates in July 2011 by $119 million, including a $21 million increase of construction surcharges, an $8 million increase of carrying charges and
Prior Fuel and Purchased Power
a $5 million decrease due to the discontinuation of the reliability surcharge. The OCCrequested increase in construction surcharges includes APCo’s West Virginia jurisdictional share of the requested purchase of the Dresden Plant, currently under construction, from AEGCo. Intervenors, including the WVPSC staff, filed a complaintmotion with the FERC relatedWVPSC to remove the allocationDresden Plant surcharge issue from this proceeding. As of off-system sales margins (OSS) among the AEP operating companies in accordance with a FERC-approved allocation agreement. The FERC issued an adverse ruling in 2008. As a result, PSO recorded a regulatory liability in 2008 to return reallocated OSS to customers. Starting in March 2009, PSO refunded the additional reallocated OSS to its customers through February 2010.
A reallocation of purchased power costs among AEP West companies for periods prior to 2002 resulted in an31, 2011, APCo’s ENEC under-recovery of $42balance was $374 million, excluding $6 million of PSO fuel costs. PSO recovered the $42 million by offsetting it against an existing fuel over-recovery during the period June 2007 through May 2008. The Oklahoma Industrial Energy Consumers (OIEC) has contended that PSO should not have collected the $42 million without specific OCC approval. As such, the OIEC contends that the OCC should require PSO to refund the $42 million it collected through its fuel clause. The OCC has heard the OIEC appeal and a decisionunrecognized equity carrying costs, which is pending. In March 2010, PSO filed motions to advance this proceeding since the FERC has ruled on the allocation of off-system sales margins and PSO has refunded the additional margins to its retail customers.included in noncurrent regulatory assets. If the OCCWVPSC were to order PSO to refund all ordisallow a partportion of the $42 million,APCo’s and WPCo’s deferred ENEC costs, it wouldcould reduce future net income and cash flows and impact financial condition.
PSO Rate Matters
PSO 2008 Fuel and Purchased Power
In July 2009, the OCC initiated a proceeding to review PSO’s fuel and purchased power adjustment clause for the calendar year 2008 and also initiated a prudenceprudency review of the related costs. In March 2010, the Oklahoma Attorney General and the OIEC recommended the fuel clause adjustment rider be amended so that the shareholder’s portion of off-system sales margins decrease from 25% to 10%. The OIECOklahoma Industrial Energy Consumers also recommended that the OCC conduct a comprehensive review of all affiliate transactions during 2007 and 2008. In July 2010, additional testimony regarding the 2007 transfer of ERCOT trading contracts to AEPEP was filed. Included in thisThe testimony wereincluded unquantified refund recommendations relating to re-pricing of contract transactions. A hearing is scheduled for January 20 11.Hearings will likely occur in the second quarter of 2011. If the OCC were to issue an unfavorable decision, it could reduce future net income and cash flows and impact financial condition. 2008 Oklahoma Base Rate Appeal
In January 2009, the OCC issued a final order approving an $81 million increase in PSO’s non-fuel base revenues based on a 10.5% return on common equity. The new rates reflecting the final order were implemented with the first billing cycle of February 2009. PSO and intervenors filed appeals with the Oklahoma Supreme Court raising various issues. The Oklahoma Supreme Court assigned the case to the Court of Civil Appeals. In June 2010, the Court of Civil Appeals affirmed the OCC's decision. No parties sought rehearing or appeal and, as a result, this case has concluded.
2010 Oklahoma Base Rate Case
In July 2010, PSO filed a request with the OCC to increase annual base rates by $82 million, including $30 million that is currently being recovered through a rider. The requested net annual increase to ratepayers would be $52 million. The requested increase includes a $24 million increase in depreciation and an 11.5% return on common equity. In October 2010, various parties, including the OCC staff, filed testimony regarding PSO’s requested base rate increase. These parties proposed that PSO's request to increase depreciation rates be denied and that existing depreciation rates continue. PSO’s request to move the $30 million currently recovered through a rider to base rates was not opposed. The parties’ net annual rate recommendations ranged from a r ate reduction of $18 million to an increase of less than $1 million based on a recommended return on common equity range from 9.5% to 10%. A hearing is scheduled for December 2010.
I&M Rate Matters
Indiana Fuel Clause FilingMichigan 2009 and 2010 Power Supply Cost Recovery (PSCR) Reconciliations (Cook Plant Unit 1 Fire and Shutdown)
I&M filed applications with the IURC to increase its fuel adjustment charge by approximately $53 million for the period of April 2009 through September 2009. The filings sought increases for previously under-recovered fuel clause expenses.
As fully discussed in the “Cook Plant Unit 1 Fire and Shutdown” section of Note 4, Cook Unit 1 (Unit 1) was shut down in September 2008 due to significant turbine damage and a small fire on the electric generator. Unit 1 was placed back into service in December 2009 at slightly reduced power. The unit outage resulted in increased replacement power fuel costs. The filing only requested the cost of replacement power through mid-December 2008, the date when I&M began receiving accidental outage insurance proceeds. I&M committed to absorb the remaining costs of replacement power through the date the unit returned to service, which occurred in December 2009.
I&M reached an agreement with intervenors, which was approved by the IURC in March 2009, to collect its existing prior period under-recovery regulatory asset deferral balance over twelve months instead of over six months as initially proposed. Under the agreement, the fuel factors were placed into effect, subject to refund, and a subdocket was established to consider issues relating to the Unit 1 shutdown including the treatment of the accidental outage insurance proceeds. I&M maintains a separate accidental outage policy with NEIL. In 2009, I&M recorded $185 million in revenue under the policy and reduced the cost of replacement power in customers’ bills by $78 million. In October 2010, the Indiana/Michigan Industrial Group and the Indiana Office of Utility Consumer Counselor filed testimony which recommended I&M pay to customers a portion of the accidental outage insurance proceeds up to the extent not previously paid to customers through the fuel adjustment clause or needed to cover costs not covered by I&M’s property damage insurance policy. Hearings are scheduled to be held in January 2011.
Management believes that I&M is entitled to retain the accidental outage insurance proceeds since it made customers whole regarding the replacement power costs. If any fuel clause revenues or accidental outage insurance proceeds have to be paid to customers, it would reduce future net income and cash flows and impact financial condition.
Michigan 2009 Power Supply Cost Recovery (PSCR) Reconciliation (Cook Plant Unit 1 Fire and Shutdown)
In March 2010, I&M filed its 2009 PSCR reconciliation with the MPSC. The filing included an adjustment to exclude from the PSCR the incremental fuel cost of replacement power due to the Cook Plant Unit 1 outage from mid-December 2008 through December 2009, the period during which I&M received and recognized the accidental outage insurance proceeds. Management believes thatIn October 2010, a settlement agreement was filed with the MPSC which included deferring the Unit 1 outage issue to the 2010 PSCR reconciliation. In March 2011, I&M is entitled to retainfiled its 2010 PSCR reconciliation with the accidental outage insurance proceeds since it made customers whole regarding the replacement power costs.MPSC. If any fuel clause revenues or accidental outage insurance proceeds have to be paid to customers, it would reduce future net income and cash flows and impact financial condition. See the “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.
Michigan Base Rate Filing
In January 2010, I&M filed with the MPSC a request for a $63 million increase in annual base rates based on an 11.75% return on common equity. Starting with the August 2010 billing cycle, I&M, with the MPSC authorization, implemented a $44 million interim rate increase. The interim increase excluded new trackers and regulatory assets for which I&M was not currently incurring expenses. In October 2010, a settlement agreement was approved by the MPSC to increase annual base rates by $36 million based on a 10.35% return on common equity, effective December 2010, plus separate recovery of approximately $7 million of customer choice implementation costs over a two year period beginning April 2011. In addition, the approved revenue requirem ent includes the amortization of $6 million in previously expensed restructuring costs over five years, which I&M will defer and begin amortizing in the fourth quarter of 2010. Also, the approved settlement agreement provided for sharing of off-system sales margins between customers (75%) and I&M (25%) with customers receiving a credit in future Power Supply Cost Recovery proceedings for their jurisdictional share of any off-system sales margins. In September 2010, I&M recorded a provision for refund of $2 million, including interest, related to the implementation of interim rates.
Kentucky Rate Matters
Kentucky Base Rate Filing
In December 2009, KPCo filed a base rate case with the KPSC to increase base revenues by $124 million annually based on an 11.75% return on common equity. The base rate case also requested recovery of deferred storm restoration expenses over a three-year period.
A settlement agreement was filed with the KPSC to increase base revenue by $64 million annually based on a 10.5% return on common equity. The settlement agreement included recovery of $23 million of deferred storm restoration expenses over five years. In June 2010, the KPSC approved the settlement agreement as filed. New rates became effective the first billing cycle of July 2010.3.
FERC Rate Matters
Regional Transmission Rate Proceedings at the FERC
Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund
In 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 2006. Intervenors objected to the temporary SECA rates. The FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund. The AEP East companies recognized gross SECA revenues of $220 million from 2004 through 2006 when the SECA rates terminated leaving the AEP East companies and ultimately their internal load retail customers to make up the shortfall in revenues.terminated.
In 2006, a FERC Administrative Law Judge (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 any unpaid SECA rates must be paid in the recommended reduced amount.
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 May 2010, the FERC issued an order that generally supports AEP’s position and requiresrequired a compliance filing to be filed with the FERC by August 2010. In June 2010, AEP and other affected companies filed a joint request for rehearing with the FERC regarding certain matters including a request to clarify the method for determining the amount of such revenues. The request also asked the FERC to clarify that interest may be added to SECA charges originally billed to but never paid by Green Mountain Energy (reassigned to British Petroleum Energy). Eight other groups also filed requests for rehearing with the FERC.
In August 2010, the affected companies, including the AEP East companies, filed a compliance filing with the FERC. If the compliance filing is accepted, the AEP East companies would have to pay refunds of approximately $20 million including estimated interest of $5 million. The AEP East companies could also potentially receive payments up to approximately $12$10 million including estimated interest of $3 million. A decision is pending from the FERC.
The FERC has approved settlements applicable to $112 million of SECA revenue. The AEP East companies provided reserves for net refunds for SECA settlements applicable to the remaining $108 million of SECA revenues collected. Based on the AEP East companies’ analysis of the May 2010 order and the compliance filing, management believes that the reserve is adequate to pay the refunds, including interest, that will be required should the May 2010 order or the compliance filing be made final. Management cannot predict the ultimate outcome of this proceeding at the FERC which could impact future net income and cash flows.
ModificationPossible Termination of the TransmissionInterconnection Agreement (TA)
APCo, CSPCo, I&M, KPCo and OPCo are parties to the TA that provides for a sharingIn December 2010, each of the costAEP Power Pool members gave notice to AEPSC and each other of transmission lines operatedtheir decision to terminate the Interconnection Agreement effective January 2014 or such other date approved by FERC, subject to state regulatory input. No filings have been made at 138-kV and above and transmission stations containing extra-high voltage facilities. In June 2009, AEPSC, on behalfthe FERC. It is unknown at this time whether the AEP Power Pool will be replaced by a new agreement among some or all of the partiesmembers, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers or if each company will choose to the TA, filed with the FERC a requestoperate independently. This decision to modify the TA. Under the proposed amendments, KGPCo and WPCo will be added as partiesterminate is subject to the TA. In addition, the amendments would provide for the allocationmanagement’s ongoing evaluation. The AEP Power Pool members may revoke their notices of PJM transmission costs on the basistermination. If any of the TA parties’ 12-month coincident peak and reimburse transmissionAEP Power Pool members experience decreases in revenues based on individual cost of service insteador increases in costs as a result of the MLR method used in the present TA. AEPSC requested the effective date to be the first daytermination of the month following a final non-appealable FERC order. T he delayed effective date was approved by the FERC when the FERC accepted the new TA for filing. In August 2010, a settlement agreement was filed with the FERC. In October 2010, the FERC approved the new TA effective November 1, 2010. The impacts of the settlement agreement will be phased-in for retail rate making purposes in certain jurisdictions over periods of up to four years. However, management isAEP Power Pool and are unable to predict whetherrecover the parties to the TA will experience regulatory lagchange in revenues and its effect oncosts through rates, prices or additional sales, it could reduce future net income and cash flows.
PJM/MISO Market Flow Calculation Settlement Adjustments
During 2009, an analysis conducted by MISO and PJM discovered several instances of unaccounted for power flows on numerous coordinated flowgates. These flows affected the settlement data for congestion revenues and expenses and datedated back to the start of the MISO market in 2005. In January 2011, PJM has providedand MISO an initial analysis of amounts they believe they owe MISO.reached a settlement agreement where the parties agreed to net various issues to zero. This settlement was filed with the FERC in January 2011. PJM and MISO disputes PJM’s methodology.are currently awaiting final approval from the FERC.
Settlement discussions between MISO and PJM have been unsuccessful, and as a result, in March 2010, MISO filed two related complaints against PJM at the FERC related to the above claim. MISO seeks to recover a total of approximately $145 million from PJM. If PJM is held liable for these damages, PJM members, including the AEP East companies, may be billed for a share of the refunds or payments PJM is directed to make to MISO. AEP has intervened and filed a protest to one complaint. Management believes that MISO's claims are without merit and that PJM's right to recover any MISO damages from AEP and other members is limited. If the FERC orders a settlement above the AEP East companies’ reserve related to their estimated portion o f PJM additional costs, it could reduce future net income and cash flows and impact financial condition.4.3. 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 20092010 Annual Report should be read in conjunction with this report.
GUARANTEES
We record liabilities for guarantees in accordance with the accounting guidance for “Guarantees.” 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 with third parties. As Parent, we issue all of these letters of credit in our ordinary course of business on behalf of our subsidiaries. These letters of credit 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 letters of credit in our ordinary course of business on behalf of our subsidiaries.
We have two $1.5 billion credit facilities, ofunder which $750 millionwe may be issued under one credit facilityissue up to $1.35 billion as letters of credit. In June 2010, we terminated oneAs of the $1.5 billion facilities that was scheduled to mature in March 31, 2011, and replaced it with a new $1.5 billion credit facility which matures in 2013 and allows for the issuance of up to $600 million as letters of credit. ;As of September 30, 2010, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $125$124 million with maturities ranging from November 2010June 2011 to November 2011.March 2012.
In June 2010,March 2011, we reduced the $627terminated a $478 million credit agreement that was scheduled to $478 million. As of September 30, 2010, $477mature in April 2011 and was used to support $472 million of letters of credit with maturities ranging from November 2010 to April 2011 were issued by subsidiaries under this credit agreement to support variable rate Pollution Control Bonds. In March 2011, we remarketed $357 million of variable rate Pollution Control Bonds using bilateral letters of credit for $361 million to support the remarketed Pollution Control Bonds. The remaining $115 million of Pollution Control Bonds were reacquired and are held by trustees.
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 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), a consolidated variable interest entity. 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 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million. As of September 30, 2010,March 31, 2011, SWEPCo has collected approximately $47$50 million through a r iderrider for final mine closure and reclamation costs, of which $1 million is recorded in Other Current Liabilities, $23$26 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $23 million is recorded in Asset Retirement Obligations on our 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
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 sale agreements is discussed in the 20092010 Annual Report “Dispositions” section of Note 7. These sale agreements include indemnifications with a maximum exposure related to the collective purchase price. This maximum exposureAs of approximately $1 billion relates to the Bank of America (BOA) litigation (se e “Enron Bankruptcy” section of this note), of which the probable payment/performance risk is $447 million and is recorded in Current Liabilities - Liability Related to Litigation on our Condensed Consolidated Balance Sheet as of September 30, 2010. The remaining exposure is remote. ThereMarch 31, 2011, there are no material liabilities recorded for any indemnifications other than amounts recorded related to the BOA litigation.indemnifications.
Master Lease Agreements
We lease certain equipment under master lease agreements. In December 2010, we signed a new master lease agreement with 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 2011, we will be required to purchase all equipment under the lease and pay GE an amount equal to the unamortized value of all equipment then leased. We are currently in negotiationsfor approximately $137 million to replace this agreement. In December 2008existing operating and 2009, we signed newcapital leases with GE. We refinanced approximately $60 million of capital leases and approximately $77 million in operating leases. These assets were included in existing master lease agreements that include lease termswere to be terminated in 2011 since GE exercised the termination provision related to these leases in 2008. As of up to 10 years.March 31, 2011, approximately $5 million was purchased and $11 million of leased assets were not included in the refinancing, but will be purchased or refinanced in the remainder of 2011.
For equipment under the GE master lease agreements, that expire in 2011, the lessor is guaranteed receipt of up to 87%78% of the unamortized balance of the equipment at the end of the lease term. If the fair 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 value and the unamortized balance, with the total guarantee not to exceed 87%78% of the unamortized balance. Under the newFor equipment under other master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, we are committed to pay the difference bet weenbetween the actual fair value and the residual value guarantee. At September 30, 2010,March 31, 2011, the maximum potential loss for these lease agreements was approximately $3$14 million assuming the fair value of the equipment is zero at the end of the lease term. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.
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 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 renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $18$17 million f orfor I&M and $20$19 million for SWEPCo for the remaining railcars as of September 30, 2010.March 31, 2011.
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 from approximately 84% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. I&M’s maximum potential loss related to the guarantee is approximately $12 million ($8 million, net of tax) and SWEPCo’s is approximately $13 million ($9 million, net of tax) assuming the fair value of the equipment is zero at the end of the current five-year lease term. However, we believe that the fair value would produce a suffic ientsufficient sales price to avoid any loss.
We have other railcar lease arrangements that do not utilize this type of financing structure.
ENVIRONMENTAL 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&M and OPCo modified certain units at their coal-fired generating plants in violation of the NSR requirements of the CAA. Cases with similar allegations against CSPCo, Dayton Power and Light Company and Duke Energy Ohio, Inc. were also filed related to their jointly-owned units. The cases were settled with the exception of a case involving a jointly-owned Beckjord unit which had a liability trial. Following the trial, the jury found no liability for claims made against the jointly-owned Beckjord unit. Following a second liability trial in 2009, the jury again found no liability at the jointly-owned Beckjord unit. The defendants and the plaintiffs appealed to the Seventh Circuit Court of Appeals. In October 2010, the Seventh Circuit dismissed all of the remaining claims in these cases. Beckjord is operated by Duke Energy Ohio, Inc.
SWEPCo Notice of Enforcement and Notice of Citizen Suit
In 2005, two special interest groups, Sierra Club and Public Citizen, filed a complaint alleging violations of the CAA at SWEPCo’s Welsh Plant. In 2008, a consent decree resolved all claims in the case and in the pending appeal of an altered permit for the Welsh Plant. The consent decree required SWEPCo to install continuous particulate emission monitors at the Welsh Plant, secure 65 MW of renewable energy capacity, fund $2 million in emission reduction, energy efficiency or environmental mitigation projects and pay a portion of plaintiffs’ attorneys’ fees and costs.
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 a previous state permit. The NOV also alleges that a permit alteration issued by the Texas Commission on Environmental Quality in 2007 was improper. In March 2008, SWEPCo met with the Federal EPA to discuss the alleged violations. 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. We are unable to determine a range of potential losses that are reasonably possible of occurring.
Carbon Dioxide Public Nuisance Claims
In 2004, eight states and the City of New York filed an action in Federal District Court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority (TVA).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 trial court dismissed the lawsuits.
In September 2009, the Second Circuit Court of Appeals issued a ruling on appeal remanding the cases to the Federal District Court for the Southern District of New York. The Second Circuit held that the issues of climate change and global warming do not raise political questions and that Congress’ refusal to regulate CO2 emissions does not mean that plaintiffs must wait for an initial policy determination by Congress or the President’s administration to secure the relief sought in their complaints. The court stated that Congress could enact comprehensive legislation to regulate CO2 emissions or that the Federal EPA could regulate CO2 emissions under existing CAA authorities and that either of these actions could override any decision made by the district court under federal common law. The Second Circuit did not rule on whether the plaintiffs could proceed with their state common law nuisance claims. TheIn December 2010, the defendants’ petition for rehearingreview by the U.S. Supreme Court was denied.granted. The case was heard in April 2011. We believe the actions are without merit and intend to continue to defend against the claims. The defendants, excluding TVA, filed a petition for review with the U.S. Supreme Court in August 2010. The Solicitor General filed a brief in support of the petition on behalf of TVA. Responses to the petition are due in November 2010.
In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina. The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims. The court granted petitions for rehearing. An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court& #8217;scourt’s decision in place. We were initially dismissed from this case without prejudice, but are named as a defendant in a pending fourth amended complaint. Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision. Responses to theThe petition are duewas denied in November 2010.January 2011.
We are unable to determine a range of potential losses that are reasonably possible of occurring.
Alaskan Villages’ Claims
In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and 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 w illwill require the relocation of the village at an alleged cost of $95
$95 million to $400 million. In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim. The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court. The plaintiffs appealed the decision. Briefing is complete and no date has been set for oral argument. The defendants requested that the court defer setting this case for oral argument until after the Supreme Court issues its decision in the CO2 public nuisance case discussed above. The court entered an order deferring argument until after June 2011. We believe the action is without merit and intend to defend against the claims. We are unable to determine a range of potential losses that are reasonably possible of occurring.
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 and other hazardous and nonhazardous materials. We currently incur costs to dispose of these substances safely.
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. In May 2008, I&M started remediation work in accordance with a plan approved by MDEQ. I&M recorded&M’s provision is approximately $11 million of expense prior to January 1, 2010, $3 million of which I&M recorded in March 2009.million. As the remediation work is completed, I&M’s cost may continue to increase as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ. We cannot predict the amount of additional cost, if any.
Amos Plant – State and Federal Enforcement Proceedings
In March 2010, we received a letter from the West Virginia Department of Environmental Protection, Division of Air Quality (DAQ), alleging that at various times in 2007 through 2009 the units at Amos Plant reported periods of excess opacity (indicator of compliance with particulate matterPM emission limits) that lasted for more than thirty30 consecutive minutes in a 24-hour period and that certain required notifications were not made. We met with representatives of DAQ to discuss these occurrences and the steps we have taken to prevent a recurrence. DAQ indicated that additional enforcement action may be taken, including imposition of a civil penalty of approximately $240 thousand. We have denied that violations of the reporting requirements occurred and maintain that the proper reporting was done. & #160;We continue to discuss the resolution ofIn March 2011, we resolved these issues with DAQ, but cannot predictthrough the outcomeentry of these discussions ora consent order that included the amountpayment of anya $75 thousand civil penalty that may be assessed.
and certain improvements in our opacity reports.
In March 2010, we received a request to show cause from the Federal EPA alleging that certain reporting requirements under Superfund and the Emergency Planning and Community Right-to-Know Act had been violated and inviting us to engage in settlement negotiations. The request includes a proposed civil penalty of approximately $300 thousand. We indicated our willingness to engage in good faith negotiations and provided additional information to representatives of the Federal EPA. We have not admitted that any violations occurred or that the amount of the proposed penalty is reasonable.
We are unable to determine a range of potential losses that are reasonably possible of occurring for either of these pending issues.
Defective Environmental Equipment
As part of our continuing environmental investment program, we chose to retrofit wet flue gas desulfurization systems on several units utilizing the jet bubbling reactor (JBR) technology. The retrofits on two Cardinal Plant units and a Conesville Plant unit are operational. Contracts for other projects were suspended during their early development stages. Due to unexpected operating results, we completed an extensive review in 2009 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. In August 2010, we signed a settlement agreement with Black & Veatch that resolved the issues involving the internal components. We also reached an agreement in principle regarding JBR vessel corrosion issues. These settlements result in an immaterial increase in the capitalized costs of the projects for modification of the scope of the contracts.
NUCLEAR CONTINGENCIES
I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission. We have a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generating units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.
Cook Plant Unit 1 Fire and Shutdown
In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in significant turbine damage and a small fire on the electric generator. This equipment, located in the turbine building, is separate and isolated from the nuclear reactor. The turbine rotors that caused the vibration were installed in 2006 and are within the vendor’s warranty period. The warranty provides for the repair or replacement of the turbine rotors if the damage was caused by a defect in materials or workmanship. Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $395 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. I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power. The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors. As a result, theThe replacement of the repaired turbine rotors and other equipment is scheduled for the Unit 1 planned outage in the fall of 2011.
I&M maintains property insurance through NEIL with a $1 million deductible.NEIL. As of September 30, 2010,March 31, 2011, we recorded $53$47 million in Prepayments and Other Current Assets on our Condensed Consolidated Balance Sheets representing recoverable amounts under the propertyNEIL insurance policy.policies. Through September 30, 2010,March 31, 2011, I&M received partial payments of $203 million from NEIL for the cost incurred to date to repair the property damage. I&M also maintains a separate accidental outage policy with NEIL. In 2009, I&M recorded $185 million in revenue under the policy and reduced the cost of replacement power in customers’ bills by $78 million.
NEIL is reviewing claims made under the insurance policies to ensure that claims associated with the outage are covered by the policies. The review by NEIL includes the timing of the unit’s return to service and whether the return should have occurred earlier reducing the amount received under the accidental outage policy. Intervenors in the Indiana fuel clause proceeding recommend the remaining accidental outage policy revenues should be given to customers through the fuel clause. The treatment of property damage costs, replacement power costs and insurance proceeds will be the subject of future regulatory proceedings in Indiana and Michigan. If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if any future regulatory proc eedingsproceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.
OPERATIONAL CONTINGENCIES
Fort Wayne Lease
Since 1975, I&M has leased certain energy delivery assets from the City of Fort Wayne, Indiana under a long-term lease that expired on February 28, 2010. I&M negotiated with Fort Wayne to purchase the assets at the end of the lease, but no agreement was reached prior to the end of the lease. Fort Wayne issued a technical notice of default under the lease to I&M in August 2009. I&M responded to Fort Wayne in October 2009 that it did not agree there was a default under the lease. In October 2009, I&M filed for declaratory and injunctive relief in Indiana state court. The parties agreed to submit this matter to mediation. In February 2010, the court issued a stay to continue mediation. I&M is expensing monthly payments made into an escrow account in lieu of rent.
I&M and Fort Wayne reached a tentative agreement as a result of the mediation process.settlement agreement. The agreement, was signed onin October 28, 2010, and is subject to approval by the Fort Wayne Common Council and the IURC. I&M andfiled a petition with the IURC seeking approval of the agreement, including recovery in rates of payments made to Fort Wayne have agreed to cooperate in promptly seeking the requisite approvals.Wayne. If the agreement is approved, I&M will purchase the remaining leased property and settle claims Fort Wayne asserted. The agreement provides that I&M will pay Fort Wayne a total of $39 million, inclusive of interest, over 15 years and Fort Wayne will recognize that I&M is the exclusive electricity supplier in the Fort Wayne area. I&M will seek recovery in ratesIn April 2011, the Indiana Office of Consumer Utility Counselor filed comments opposing portions of the payments made to Fort Wayne. I fsettlement agreement. The IURC scheduled a hearing for June 2011. If the agreement is not approved by the Fort Wayne Common Council and the IURC, the parties have the right to terminate the agreement and pursue other relief.
Enron Bankruptcy
In 2001, we purchased Houston 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 arrangem ent.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 beingwas 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 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 Y ork and retaining in the Southern District of Texas the four counts alleging breach of contract, fraud and negligent misrepresentation. Trial in federal court in Texas was continued pending a decision in the New York case.
In 2007, the judge in the New York action issued a decision on all claims, including those that were pending trial in Texas, granting BOA summary judgment and dismissing our claims. In August 2008, the New York court entered a final judgment of $346 million. We appealed and posted a bond covering the amount of the judgment entered against us. In May 2009, the judge awarded $20 million of attorneys’ fees to BOA. We appealed this awardthese awards and posted bondbonds covering that amount.the amounts. In October 2010, the Court of Appeals affirmed the New York district court'scourt’s decision as to the final judgment of $346 million and reversed the New York district court decision as to the judgment dismissing our claims against BOA in the Southern District of Texas.
In 2005, we sold our interest in HPL for approximately $1 billion. Although the assets were legally transferred, we were unable to determine all costs associated with the transfer until the BOA litigation was resolved. We intendindemnified the buyer of HPL against any damages up to pursue these claims in Texas . The liability forthe purchase price resulting from the BOA litigation, including the right to use the 55 BCF of natural gas through 2031. As a result, we deferred the entire gain related to the sale of HPL (approximately $380 million) pending resolution of the Enron and BOA disputes.
The deferred gain related to the sale of HPL, plus accrued interest and attorneys’ fees related to the New York court’s judgment was $447$448 million at September 30,December 31, 2010 and iswas included in Current Liabilities - Liability Related to– Deferred Gain and Accrued Litigation Costs on the Condensed Consolidated Balance Sheet. $441
In February 2011, we reached a settlement covering all claims with BOA and Enron for $425 million. As part of the settlement, we received title to the 55 BCF of natural gas in the Bammel storage facility and recorded this asset at fair value. Under the HPL sales agreement, we have a service obligation to the buyer for the right to use the cushion gas through May 2031. We recognized the obligation as a liability and will amortize it over the life of the agreement.
The settlement resulted in a pretax gain of $51 million relatedand a net loss after tax of $22 million primarily due to this matter was included in Deferred Credits and Other Noncurrent Liabilitiesan unrealized capital loss valuation allowance of $56 million.
The following table sets forth the impact of the settlement on our Condensed Consolidated Balance Sheet at December 31, 2009. This decision will have no impact on consolidated net income for 2010.financial statements:
| | | |
| | | |
| Three Months Ended |
| March 31, 2011 |
| (in millions) |
Income Statement: | | | |
Other Operation Expense - Pretax Gain on Settlement | $ | | 51 |
Income Tax Expense | | | 73 |
Net Loss After Tax | $ | | (22) |
| | | |
Cash Flow Statement: | | | |
Net Income - Loss on Settlement with BOA and Enron | $ | | (22) |
Deferred Income Taxes | | | 91 |
Gain on Settlement with BOA and Enron | | | (51) |
Settlement of Litigation with BOA and Enron | | | (211) |
Accrued Taxes, Net | | | (18) |
Acquisition of Cushion Gas from BOA | | | (214) |
Cash Paid | $ | | (425) |
| | | |
| March 31, 2011 |
| (in millions) |
Balance Sheet: | | | |
Deferred Charges and Other Noncurrent Assets - Gas Acquired | $ | | 214 |
Deferred Credits and Other Noncurrent Liabilities - Gas Service Liability | | | 187 |
Accrued Taxes - Tax Benefit on Settlement with BOA and Enron | | | 18 |
Deferred Income Taxes - Deferred Tax Benefit on Gas Service Liability | | | 66 |
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 2008, we settled all of the cases pending against us in Ca lifornia. The settlements did not impact 2008 earnings due to provisions made in prior periods.California. We will continue to defend each remaining case where an AEP company is a defendant. We believe the provision we have for the remaining cases is adequate. We are unable to determine a range of potential losses that are reasonably possible of occurring.believe the remaining exposure is immaterial.
5.4. ACQUISITION AND DISPOSITIONS
ACQUISITION
2011
None
2010
Valley Electric Membership Corporation (Utility Operations segment)
In November 2009,October 2010, SWEPCo signed a letter of intent to purchasepurchased certain transmission and distribution assets of Valley Electric Membership Corporation (VEMCO). In October 2010, SWEPCo finalized the purchase for approximately $102 million subject to working capital and other adjustments, and began serving VEMCO’s 30,000 customers in Louisiana.
2009DISPOSITIONS
None2011
Electric Transmission Texas LLC (ETT) (Utility Operations segment) DISPOSITIONSTCC sold, at cost, $5 million of transmission facilities to ETT for the three months ended March 31, 2011.
2010
Electric Transmission Texas LLC (ETT) (Utility Operations segment)
TCC and TNC sold, $66at cost, $64 million and $73$71 million, respectively, of transmission facilities to ETT for the ninethree months ended September 30,March 31, 2010. There were no gains or losses recorded on these transactions.
Intercontinental Exchange, Inc. (ICE) (All Other)In April 2010, we sold our remaining 138,000 shares of ICE and recognized a $16 million gain ($10 million, net of tax). We recorded the gain in Interest and Investment Income on our Condensed Consolidated Statements of Income for the nine months ended September 30, 2010.
2009
Electric Transmission Texas LLC (ETT) (Utility Operations segment)
TCC and TNC sold $93 million and $1 million, respectively, of transmission facilities to ETT for the nine months ended September 30, 2009. There were no gains or losses recorded on these transactions.
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, 2010March 31, 2011 and 2009:2010:
| | | Other Postretirement | |
| Pension Plans | | Benefit Plans | |
| Three Months Ended September 30, | | Three Months Ended September 30, | |
| 2010 | | 2009 | | 2010 | | 2009 | |
| (in millions) | |
Service Cost | | $ | 28 | | | $ | 26 | | | $ | 12 | | | $ | 11 | |
Interest Cost | | | 63 | | | | 64 | | | | 29 | | | | 27 | |
Expected Return on Plan Assets | | | (78 | ) | | | (80 | ) | | | (27 | ) | | | (21 | ) |
Amortization of Transition Obligation | | | - | | | | - | | | | 6 | | | | 7 | |
Amortization of Net Actuarial Loss | | | 22 | | | | 14 | | | | 8 | | | | 11 | |
Net Periodic Benefit Cost | | $ | 35 | | | $ | 24 | | | $ | 28 | | | $ | 35 | |
| | | 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, |
| 2010 | | 2009 | | 2010 | | 2009 | | 2011 | | 2010 | | 2011 | | 2010 |
| (in millions) | | (in millions) |
Service Cost | | $ | 83 | | | $ | 78 | | | $ | 35 | | | $ | 32 | | $ | 18 | | $ | 28 | | $ | 11 | | $ | 12 |
Interest Cost | | | 190 | | | | 191 | | | | 85 | | | | 82 | | | 59 | | | 63 | | | 27 | | | 28 |
Expected Return on Plan Assets | | | (234 | ) | | | (241 | ) | | | (79 | ) | | | (61 | ) | | (79) | | | (78) | | | (27) | | | (26) |
Amortization of Transition Obligation | | | - | | | | - | | | | 20 | | | | 20 | | | - | | | - | | | - | | | 7 |
Amortization of Net Actuarial Loss | | | 67 | | | | 44 | | | | 22 | | | | 32 | | | 30 | | | 22 | | | 7 | | | 7 |
Net Periodic Benefit Cost | | $ | 106 | | | $ | 72 | | | $ | 83 | | | $ | 105 | | $ | 28 | | $ | 35 | | $ | 18 | | $ | 28 |
We made a $350 million voluntary contribution to the qualified pension trust in September 2010. This contribution is in addition to the $150 million contribution that we are making ratably throughout 2010. We made no contributions in 2009.
7.6. BUSINESS SEGMENTS
As outlined in our 20092010 Annual Report, our primary business is 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. 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.area and to a lesser extent Ohio in PJM and MISO. 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.· | Generation of electricity for sale to U.S. retail and wholesale customers. |
· Electricity transmission and distribution in the U.S.· | Electricity transmission and distribution in the U.S. |
AEP River Operations
· Commercial barging operations that transport coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi River.
· | Commercial barging operations that transport coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers. |
Generation and Marketing
· Wind farms and marketing and risk management activities primarily in ERCOT.· | Wind farms and marketing and risk management activities primarily in ERCOT and to a lesser extent Ohio in PJM and MISO. |
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 settle and completely expire in the fourth quarter of 2011. |
· | Revenue sharing related to the Plaquemine Cogeneration Facility.Facility which ends in the fourth quarter of 2011. |
The tables below present our reportable segment information for the three and nine months ended September 30,March 31, 2011 and 2010 and 2009 and balance sheet information as of September 30, 2010March 31, 2011 and December 31, 2009.2010. These amounts include certain estimates and allocations where necessary.
| | | | | | | | Nonutility Operations | | | | | | | | | | Nonutility Operations | | | | | | | | | | |
| | | | | | | | | | | Generation | | | | | | | | | | | | | | | | Generation | | | | | | | | | | |
| | | Utility | | AEP River | and | All Other | Reconciling | | | Utility | | AEP River | | and | | All Other | | Reconciling | | | | |
| | | Operations | | Operations | Marketing | (a) | Adjustments | Consolidated | Operations | | Operations | | Marketing | | (a) | | Adjustments | | Consolidated | |
| | | | (in millions) | (in millions) | |
Three Months Ended September 30, 2010 | | | | | | | | | | | | | | | |
Three Months Ended March 31, 2011 | | | | | | | | | | | | | | | | | | | |
Revenues from: | Revenues from: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | External Customers | | $ | 3,876 | | | $ | 147 | | $ | 41 | | $ | - | | $ | - | | $ | 4,064 | |
| | Other Operating Segments | | | 31 | | | | 7 | | | - | | | 3 | | | (41) | | | - | |
External Customers | | | $ | 3,497 | | | $ | 167 | | | $ | 62 | | | $ | 4 | | | $ | - | | | $ | 3,730 | |
Other Operating Segments | | | | 27 | | | | 5 | | | | 1 | | | | 1 | | | | (34 | ) | | | - | |
Total Revenues | Total Revenues | | $ | 3,907 | | | $ | 154 | | $ | 41 | | $ | 3 | | $ | (41) | | $ | 4,064 | | $ | 3,524 | | | $ | 172 | | | $ | 63 | | | $ | 5 | | | $ | (34 | ) | | $ | 3,730 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net Income | | $ | 541 | | | $ | 14 | | $ | - | | $ | 2 | | $ | - | | $ | 557 | |
Net Income (Loss) | | | $ | 378 | | | $ | 7 | | | $ | 1 | | | $ | (31 | ) | | $ | - | | | $ | 355 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Nonutility Operations | | | | | | | | | | | Nonutility Operations | | | | | | | | | | | | | |
| | | | | | | | | | | Generation | | | | | | | | | | | | | | | | | | Generation | | | | | | | | | | | | | |
| | | Utility | | AEP River | and | All Other | Reconciling | | | Utility | | AEP River | | and | | All Other | | Reconciling | | | | | |
| | | Operations | | Operations | Marketing | (a) | Adjustments | Consolidated | Operations | | Operations | | Marketing | | (a) | | Adjustments | | Consolidated | |
| | | | (in millions) | (in millions) | |
Three Months Ended September 30, 2009 | | | | | | | | | | | | | | | |
Three Months Ended March 31, 2010 | | | | | | | | | | | | | | | | | | | | | | | | | |
Revenues from: | Revenues from: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | External Customers | | $ | 3,364 | (d) | | $ | 113 | | $ | 68 | | $ | 2 | | $ | - | | $ | 3,547 | |
| | Other Operating Segments | | | 25 | (d) | | | 4 | | | - | | | 1 | | | (30) | | | - | |
External Customers | | | $ | 3,406 | | | $ | 121 | | | $ | 47 | | | $ | (5 | ) | | $ | - | | | $ | 3,569 | |
Other Operating Segments | | | | 20 | | | | 5 | | | | - | | | | 8 | | | | (33 | ) | | | - | |
Total Revenues | Total Revenues | | $ | 3,389 | | | $ | 117 | | $ | 68 | | $ | 3 | | $ | (30) | | $ | 3,547 | | $ | 3,426 | | | $ | 126 | | | $ | 47 | | | $ | 3 | | | $ | (33 | ) | | $ | 3,569 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Income (Loss) Before Extraordinary Loss | | $ | 448 | | | $ | 10 | | $ | 5 | | $ | (17) | | $ | - | | $ | 446 | |
Extraordinary Loss, Net of Tax | | | - | | | | - | | | - | | | - | | | - | | | - | |
Net Income (Loss) | Net Income (Loss) | | $ | 448 | | | $ | 10 | | $ | 5 | | $ | (17) | | $ | - | | $ | 446 | | $ | 344 | | | $ | 3 | | | $ | 10 | | | $ | (11 | ) | | $ | - | | | $ | 346 | |
| | | | | | | | Nonutility Operations | | | | | | | | | |
| | | | | | | | | | | Generation | | | | | | | | | |
| | | Utility | | AEP River | and | All Other | Reconciling | | |
| | | Operations | | Operations | Marketing | (a) | Adjustments | Consolidated |
| | | | (in millions) |
Nine Months Ended September 30, 2010 | | | | | | | | | | | | | | | | | | | |
Revenues from: | | | | | | | | | | | | | | | | | | | |
| | External Customers | | $ | 10,468 | | | $ | 395 | | $ | 130 | | $ | - | | $ | - | | $ | 10,993 |
| | Other Operating Segments | | | 76 | | | | 17 | | | - | | | 10 | | | (103) | | | - |
Total Revenues | | $ | 10,544 | | | $ | 412 | | $ | 130 | | $ | 10 | | $ | (103) | | $ | 10,993 |
| | | | | | | | | | | | | | | | | | | | | |
Net Income (Loss) | | $ | 1,017 | | | $ | 16 | | $ | 17 | | $ | (10) | | $ | - | | $ | 1,040 |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Nonutility Operations | | | | | | | | | |
| | | | | | | | | | | Generation | | | | | | | | | |
| | | Utility | | AEP River | and | All Other | Reconciling | | |
| | | Operations | | Operations | Marketing | (a) | Adjustments | Consolidated |
| | | | (in millions) |
Nine Months Ended September 30, 2009 | | | | | | | | | | | | | | | | | | | |
Revenues from: | | | | | | | | | | | | | | | | | | | |
| | External Customers | | $ | 9,666 | (d) | | $ | 341 | | $ | 213 | | $ | (13) | | $ | - | | $ | 10,207 |
| | Other Operating Segments | | | 46 | (d) | | | 13 | | | 6 | | | 28 | | | (93) | | | - |
Total Revenues | | $ | 9,712 | | | $ | 354 | | $ | 219 | | $ | 15 | | $ | (93) | | $ | 10,207 |
| | | | | | | | | | | | | | | | | | | | | |
Income (Loss) Before Extraordinary Loss | | $ | 1,121 | | | $ | 22 | | $ | 33 | | $ | (45) | | $ | - | | $ | 1,131 |
Extraordinary Loss, Net of Tax | | | (5) | | | | - | | | - | | | - | | | - | | | (5) |
Net Income (Loss) | | $ | 1,116 | | | $ | 22 | | $ | 33 | | $ | (45) | | $ | - | | $ | 1,126 |
| | | | Nonutility Operations | | | | | | | | | | | | | | | | | | Nonutility Operations | | | | | | | | | |
| | | | | | | Generation | | | | | Reconciling | | | | | | | | | | | | | | | Generation | | | | | Reconciling | | | |
| Utility | | AEP River | | and | | All Other | | Adjustments | | | | | | | | Utility | | AEP River | | and | | All Other | | Adjustments | | | |
| Operations | | Operations | | Marketing | | (a) | | (b) | | | Consolidated | | | | Operations | | Operations | | Marketing | | (a) | | (b) | | Consolidated |
| (in millions) | | | | | (in millions) |
September 30, 2010 | | | | | | | | | | | | | | | | | | | | |
March 31, 2011 | | March 31, 2011 | | | | | | | | | | | | | | | | | |
Total Property, Plant and Equipment | | $ | 52,041 | | | $ | 542 | | | $ | 584 | | | $ | 10 | | | $ | (250 | ) | | | $ | 52,927 | | Total Property, Plant and Equipment | | $ | 53,162 | | $ | 589 | | $ | 593 | | $ | 10 | | $ | (258) | | $ | 54,096 |
Accumulated Depreciation and Amortization | | | 17,667 | | | | 105 | | | | 191 | | | | 9 | | | | (43 | ) | | | | 17,929 | | Accumulated Depreciation and Amortization | | | 18,049 | | | 117 | | | 204 | | | 9 | | | (49) | | | 18,330 |
Total Property, Plant and Equipment - Net | | $ | 34,374 | | | $ | 437 | | | $ | 393 | | | $ | 1 | | | $ | (207 | ) | | | $ | 34,998 | | Total Property, Plant and Equipment - Net | | $ | 35,113 | | $ | 472 | | $ | 389 | | $ | 1 | | $ | (209) | | $ | 35,766 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 47,964 | | | $ | 603 | | | $ | 898 | | | $ | 15,621 | | | $ | (15,194 | ) | (c) | | $ | 49,892 | | Total Assets | | $ | 48,772 | | $ | 652 | | $ | 835 | | $ | 15,713 | | $ | (15,412) | (c) | $ | 50,560 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Nonutility Operations | | | | | | | | | | | | | | | | | | | | | Nonutility Operations | | | | | | | | | |
| | | | | | | | | Generation | | | | | | Reconciling | | | | | | | | | | | | | | | | Generation | | | | | Reconciling | | | |
| Utility | | AEP River | | and | | All Other | | Adjustments | | | | | | | | | Utility | | AEP River | | and | | All Other | | Adjustments | | | |
| Operations | | Operations | | Marketing | | (a) | | (b) | | | Consolidated | | | | Operations | | Operations | | Marketing | | (a) | | (b) | | Consolidated |
| (in millions) | | | | | (in millions) |
December 31, 2009 | | | | | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2010 | | December 31, 2010 | | | | | | | | | | | | | | | | | |
Total Property, Plant and Equipment | | $ | 50,905 | | | $ | 436 | | | $ | 571 | | | $ | 10 | | | $ | (238 | ) | | | $ | 51,684 | | Total Property, Plant and Equipment | | $ | 52,822 | | $ | 574 | | $ | 584 | | $ | 11 | | $ | (251) | | $ | 53,740 |
Accumulated Depreciation and Amortization | | | 17,110 | | | | 88 | | | | 168 | | | | 8 | | | | (34 | ) | | | | 17,340 | | Accumulated Depreciation and Amortization | | | 17,795 | | | 110 | | | 198 | | | 9 | | | (46) | | | 18,066 |
Total Property, Plant and Equipment - Net | | $ | 33,795 | | | $ | 348 | | | $ | 403 | | | $ | 2 | | | $ | (204 | ) | | | $ | 34,344 | | Total Property, Plant and Equipment - Net | | $ | 35,027 | | $ | 464 | | $ | 386 | | $ | 2 | | $ | (205) | | $ | 35,674 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 46,930 | | | $ | 495 | | | $ | 779 | | | $ | 15,094 | | | $ | (14,950 | ) | (c) | | $ | 48,348 | | Total Assets | | $ | 48,780 | | $ | 621 | | $ | 881 | | $ | 15,942 | | $ | (15,769) | (c) | $ | 50,455 |
· | 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 settle and completely expire in the fourth quarter of 2011. |
· | Revenue sharing related to the Plaquemine Cogeneration Facility.Facility which ends in the fourth quarter of 2011. |
(b) | Includes eliminations due to an intercompany capital lease. |
(c) | 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. |
(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 was offset by the Utility Operations segment's related net sales (purchases) for these contracts with AEPEP in Revenues from Other Operating Segments of $(113) thousand and $(6) million for the three and nine months ended September 30, 2009, respectively. The Generation and Marketing segment also reported these purchase or sales contracts with Utility Operations as Revenues from Other Operating Segments. These affiliated contracts between PSO and SWE PCo with AEPEP ended in December 2009. |
8.7. 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 risks using derivative instruments.
STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES
Trading Strategies
Our strategy surrounding the use of derivative instruments for trading purposes focuses on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which we transact.
Risk Management Strategies
Our strategy surrounding the use of derivative instruments focuses on managing our risk exposures, future cash flows and creating value utilizing both economic and formal 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 the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.
We enter into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and 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 d etermineddetermined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of AEP’sour Board of Directors.
The following table represents the gross notional volume of our outstanding derivative contracts as of September 30, 2010March 31, 2011 and December 31, 2009:2010:
Notional Volume of Derivative Instruments |
| | | | | | | |
| Volume | | |
| | September 30, | | | December 31, | | Unit of |
| | 2010 | | | 2009 | | Measure |
| (in millions) | | |
Commodity: | | | | | | | |
Power | | | 789 | | | | 589 | | MWHs |
Coal | | | 71 | | | | 60 | | Tons |
Natural Gas | | | 110 | | | | 127 | | MMBtus |
Heating Oil and Gasoline | | | 7 | | | | 6 | | Gallons |
Interest Rate | | $ | 180 | | | $ | 216 | | USD |
| | | | | | | | | |
Interest Rate and Foreign Currency | | $ | 664 | | | $ | 83 | | USD |
Notional Volume of Derivative Instruments |
| | | | | | | | | |
| | | Volume | | |
| | | March 31, | | December 31, | | Unit of |
| | 2011 | | 2010 | | Measure |
| | | (in millions) | |
Commodity: | | | | | | | | |
| Power | | | 539 | | | 652 | | MWHs |
| Coal | | | 60 | | | 63 | | Tons |
| Natural Gas | | | 89 | | | 94 | | MMBtus |
| Heating Oil and Gasoline | | | 6 | | | 6 | | Gallons |
| Interest Rate | | $ | 273 | | $ | 171 | | USD |
| | | | | | | | | |
Interest Rate and Foreign Currency | | $ | 503 | | $ | 907 | | USD |
Fair Value Hedging Strategies
We enter into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain 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. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.
Cash Flow Hedging Strategies
We enter into and designate as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“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 and barge operations are exposed to gasoline and diesel fuel price volatility. We enter into financial heating oil and gasoline derivative contracts in order to mitigate price risk of our future fuel purchases. We do not hedge all fuel price risk. For disclosure purposes, these contracts are included with other hedging activity as “Commodity.”
We do not hedge all fuel price risk.
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
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON OUR FINANCIAL STATEMENTS |
The accounting guidance for “Derivatives and Hedging” 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 conse nsusconsensus 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 the accounting guidance for “Derivatives and Hedging,” 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 September 30, 2010March 31, 2011 and December 31, 20092010 balance sheets, we netted $20$7 million and $12$8 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $228$70 million and $98$109 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.
The following tables represent the gross fair value impact of our derivative activity on our Condensed Consolidated Balance Sheets as of September 30, 2010March 31, 2011 and December 31, 2009:2010:
Fair Value of Derivative Instruments | Fair Value of Derivative Instruments | | Fair Value of Derivative Instruments |
September 30, 2010 | | |
March 31, 2011 | | March 31, 2011 |
| | | |
| | Risk Management | | | | | | | | | | | | Risk Management | | | | | | | | |
| | Contracts | | Hedging Contracts | | | | | | | | Contracts | | Hedging Contracts | | | | |
| | | | | | Interest Rate | | | | | | | | | | | | Interest Rate | | | | |
| | | | | | and Foreign | | Other | | | | | | | | | | and Foreign | | | | |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Currency (a)(c) | | (a) (b) | | Total | | Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Currency (a) | | Other (a)(b) | | Total |
| | (in millions) | | | | (in millions) |
Current Risk Management Assets | | | $ | 1,229 | | | $ | 16 | | | $ | 4 | | | $ | (970 | ) | | $ | 279 | | Current Risk Management Assets | | $ | 833 | | $ | 21 | | $ | 5 | | $ | (666) | | $ | 193 |
Long-term Risk Management Assets | | | | 835 | | | | 10 | | | | 3 | | | | (360 | ) | | | 488 | | Long-term Risk Management Assets | | | 526 | | | 11 | | | 1 | | | (179) | | | 359 |
Total Assets | | | | 2,064 | | | | 26 | | | | 7 | | | | (1,330 | ) | | | 767 | | Total Assets | | | 1,359 | | | 32 | | | 6 | | | (845) | | | 552 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | | | | 1,167 | | | | 19 | | | | 3 | | | | (1,065 | ) | | | 124 | | Current Risk Management Liabilities | | 807 | | 13 | | 2 | | (713) | | 109 |
Long-term Risk Management Liabilities | | | | 687 | | | | 4 | | | | 3 | | | | (527 | ) | | | 167 | | Long-term Risk Management Liabilities | | | 364 | | | 7 | | | 3 | | | (236) | | | 138 |
Total Liabilities | | | | 1,854 | | | | 23 | | | | 6 | | | | (1,592 | ) | | | 291 | | Total Liabilities | | | 1,171 | | | 20 | | | 5 | | | (949) | | | 247 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | | $ | 210 | | | $ | 3 | | | $ | 1 | | | $ | 262 | | | $ | 476 | | |
Total MTM Derivative Contract Net Assets | | Total MTM Derivative Contract Net Assets | | | | | | | | | | |
| | (Liabilities) | | $ | 188 | | $ | 12 | | $ | 1 | | $ | 104 | | $ | 305 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Fair Value of Derivative Instruments | Fair Value of Derivative Instruments | | Fair Value of Derivative Instruments |
December 31, 2009 | | |
December 31, 2010 | | December 31, 2010 |
| | | |
| | Risk Management | | | | | | | | | | | | | | | | | | | | Risk Management | | | | | | | | |
| | Contracts | | Hedging Contracts | | | | | | | | | | | | Contracts | | Hedging Contracts | | | | |
| | | | | | | | | | Interest Rate | | | | | | | | | | | | | | | | Interest Rate | | | | |
| | | | | | | | | and Foreign | | Other | | | | | | | | | | | | and Foreign | | | | |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Currency (a) | | (a) (b) | | Total | | Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Currency (a) | | Other (a)(b) | | Total |
| | (in millions) | | | | (in millions) |
Current Risk Management Assets | | | $ | 1,078 | | | $ | 13 | | | $ | - | | | $ | (831 | ) | | $ | 260 | | Current Risk Management Assets | | $ | 1,023 | | $ | 18 | | $ | 30 | | $ | (839) | | $ | 232 |
Long-term Risk Management Assets | | | | 614 | | | | - | | | | - | | | | (271 | ) | | | 343 | | Long-term Risk Management Assets | | | 546 | | | 12 | | | 2 | | | (150) | | | 410 |
Total Assets | | | | 1,692 | | | | 13 | | | | - | | | | (1,102 | ) | | | 603 | | Total Assets | | | 1,569 | | | 30 | | | 32 | | | (989) | | | 642 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | | | | 997 | | | | 17 | | | | 3 | | | | (897 | ) | | | 120 | | Current Risk Management Liabilities | | 995 | | 13 | | 2 | | (881) | | 129 |
Long-term Risk Management Liabilities | | | | 442 | | | | - | | | | 2 | | | | (316 | ) | | | 128 | | Long-term Risk Management Liabilities | | | 387 | | | 6 | | | 3 | | | (255) | | | 141 |
Total Liabilities | | | | 1,439 | | | | 17 | | | | 5 | | | | (1,213 | ) | | | 248 | | Total Liabilities | | | 1,382 | | | 19 | | | 5 | | | (1,136) | | | 270 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net Assets (Liabilities) | | | $ | 253 | | | $ | (4 | ) | | $ | (5 | ) | | $ | 111 | | | $ | 355 | | |
Total MTM Derivative Contract Net Assets | | Total MTM Derivative Contract Net Assets | | | | | | | | | | |
| | (Liabilities) | | $ | 187 | | $ | 11 | | $ | 27 | | $ | 147 | | $ | 372 |
| | Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the Condensed Consolidated Balance SheetSheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." |
| (b) | Amounts representinclude counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging" andHedging." Amounts also include dedesignated risk management contracts. |
| (c) | At September 30, 2010, Risk Management Assets included $7 million related to fair value hedging strategies while the remainder related to cash flow hedging strategies. At December 31, 2009, we only employed cash flow hedging strategies. |
The table below presents our activity of derivative risk management contracts for the three and nine months ended September 30, 2010March 31, 2011 and 2009:2010:
Amount of Gain (Loss) Recognized on |
Risk Management Contracts |
For the Three Months Ended September 30, 2010 and 2009 |
| | | | |
Location of Gain (Loss) | | 2010 | | 2009 |
| | (in millions) |
Utility Operations Revenue | | $ | 24 | | $ | 25 |
Other Revenue | | | (4) | | | 1 |
Regulatory Assets (a) | | | (6) | | | (7) |
Regulatory Liabilities (a) | | | 7 | | | 24 |
Total Gain (Loss) on Risk Management Contracts | | $ | 21 | | $ | 43 |
| | | | | | |
Amount of Gain (Loss) Recognized on |
Risk Management Contracts |
For the Nine Months Ended September 30, 2010 and 2009 |
| | | | |
Location of Gain (Loss) | | 2010 | | 2009 |
| | (in millions) |
Utility Operations Revenue | | $ | 69 | | $ | 124 |
Other Revenue | | | 5 | | | 19 |
Regulatory Assets (a) | | | (9) | | | (17) |
Regulatory Liabilities (a) | | | 34 | | | 33 |
Total Gain (Loss) on Risk Management Contracts | | $ | 99 | | $ | 159 |
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatmentAmount of Gain (Loss) Recognized on |
Risk Management Contracts |
For the Three Months Ended March 31, 2011 and 2010 |
| | | | | | | |
Location of Gain (Loss) | | | 2011 | | | 2010 |
| | | (in millions) |
Utility Operations Revenue | | | $ | 20 | | $ | 38 |
Other Revenue | | | | 2 | | | 1 |
Regulatory Assets (a) | | | | 2 | | | - |
Regulatory Liabilities (a) | | | | 8 | | | 42 |
Total Gain on Risk Management Contracts | | | $ | 32 | | $ | 81 |
| | | | | | | |
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheet. |
recorded as either current or non-current on the balance sheet.
Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on 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 on 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 some 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 ga ins)gains) in accordance with the accounting guidance for “Regulated Operations.”
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 and unrealized 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 and nine months ended September 30, 2010,March 31, 2011, we recognized gains of $3$4 million and $7 million, respectively, on our outstanding hedging instruments, with offsetting losses of $3$4 million and $7 million, respectively, on our long-term debt.debt and an immaterial amount of hedge ineffectiveness. During the three and nine months ended September 30,March 31, 2010, the value of the hedging instruments was immaterial and no hedge ineffectiveness was recognized. During the three and nine months ended September 30, 2009, we did not employ any fair value hedging strategies.
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 power, coal, natural gas and heating oil and gasoline designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on our Condensed Consolidated Statements of Income, or in Regulatory Assets or Regulatory Liabilities on our Condensed Consolidated Balance Sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30,March 31, 2011 and 2010, and 2009, we designated commodity derivatives as cash flow hedges.
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 expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our Condensed Consolidated Statements of Income. During the three and nine months ended September 30,March 31, 2011 and 2010, and 2009, we designated heating oil and gasoline derivatives as cash flow hedges.
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 and nine months ended September 30,March 31, 2011 and 2010, and 2009, we designated interest rate derivatives as cash flow hedges.
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 on 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. During the three and nine months ended September 30,March 31, 2011 and 2010, and 2009, we designated foreign currency derivatives as cash flow hedges.
During the three and nine months ended September 30,March 31, 2011 and 2010, and 2009, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.
The following tables provide details on designated, effective cash flow hedges included in AOCIAccumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2010March 31, 2011 and 2009.2010. All amounts in the following tabletables are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | |
For the Three Months Ended September 30, 2010 | |
| | | | Interest Rate | | | | |
| | | | and Foreign | | | | |
| Commodity | | Currency | | Total | |
| (in millions) | |
Balance in AOCI as of June 30, 2010 | | $ | 2 | | | $ | (15 | ) | | $ | (13 | ) |
Changes in Fair Value Recognized in AOCI | | | (2 | ) | | | (1 | ) | | | (3 | ) |
Amount of (Gain) or Loss Reclassified from AOCI | | | | | | | | | | | | |
to Income Statement/within Balance Sheet: | | | | | | | | | | | | |
Utility Operations Revenue | | | 1 | | | | - | | | | 1 | |
Other Revenue | | | (1 | ) | | | - | | | | (1 | ) |
Purchased Electricity for Resale | | | 1 | | | | - | | | | 1 | |
Interest Expense | | | - | | | | 1 | | | | 1 | |
Regulatory Assets (a) | | | 1 | | | | - | | | | 1 | |
Regulatory Liabilities (a) | | | - | | | | - | | | | - | |
Balance in AOCI as of September 30, 2010 | | $ | 2 | | | $ | (15 | ) | | $ | (13 | ) |
| | | | | | | | | | | | |
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | |
For the Three Months Ended September 30, 2009 | |
| | | | | Interest Rate | | | | | |
| | | | | and Foreign | | | | | |
| Commodity | | Currency | | Total | |
| (in millions) | |
Balance in AOCI as of June 30, 2009 | | $ | 6 | | | $ | (11 | ) | | $ | (5 | ) |
Changes in Fair Value Recognized in AOCI | | | (6 | ) | | | (4 | ) | | | (10 | ) |
Amount of (Gain) or Loss Reclassified from AOCI | | | | | | | | | | | | |
to Income Statement/within Balance Sheet: | | | | | | | | | | | | |
Utility Operations Revenue | | | (7 | ) | | | - | | | | (7 | ) |
Other Revenue | | | (5 | ) | | | - | | | | (5 | ) |
Purchased Electricity for Resale | | | 10 | | | | - | | | | 10 | |
Interest Expense | | | - | | | | 1 | | | | 1 | |
Regulatory Assets (a) | | | 2 | | | | - | | | | 2 | |
Regulatory Liabilities (a) | | | (3 | ) | | | - | | | | (3 | ) |
Balance in AOCI as of September 30, 2009 | | $ | (3 | ) | | $ | (14 | ) | | $ | (17 | ) |
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges |
For the Three Months Ended March 31, 2011 |
| | | | | | | Interest Rate | | | |
| | | | | | | and Foreign | | | |
| | | | Commodity | | Currency | | Total |
| | | | (in millions) |
Balance in AOCI as of December 31, 2010 | | $ | 7 | | $ | 4 | | $ | 11 |
Changes in Fair Value Recognized in AOCI | | | 2 | | | (1) | | | 1 |
Amount of (Gain) or Loss Reclassified from AOCI | | | | | | | | | |
| to Income Statement/within Balance Sheet: | | | | | | | | | |
| | Utility Operations Revenue | | | - | | | - | | | - |
| | Other Revenue | | | (1) | | | - | | | (1) |
| | Purchased Electricity for Resale | | | - | | | - | | | - |
| | Interest Expense | | | - | | | 1 | | | 1 |
| | Regulatory Assets (a) | | | - | | | - | | | - |
| | Regulatory Liabilities (a) | | | - | | | - | | | - |
Balance in AOCI as of March 31, 2011 | | $ | 8 | | $ | 4 | | $ | 12 |
| | | | | | | | | | | |
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges |
For the Three Months Ended March 31, 2010 |
| | | | | | | Interest Rate | | | |
| | | | | | | and Foreign | | | |
| | | | Commodity | | Currency | | Total |
| | | | (in millions) |
Balance in AOCI as of December 31, 2009 | | $ | (2) | | $ | (13) | | $ | (15) |
Changes in Fair Value Recognized in AOCI | | | 3 | | | (1) | | | 2 |
Amount of (Gain) or Loss Reclassified from AOCI | | | | | | | | | |
| to Income Statement/within Balance Sheet: | | | | | | | | | |
| | Utility Operations Revenue | | | - | | | - | | | - |
| | Other Revenue | | | (1) | | | - | | | (1) |
| | Purchased Electricity for Resale | | | 1 | | | - | | | 1 |
| | Interest Expense | | | - | | | 1 | | | 1 |
| | Regulatory Assets (a) | | | 1 | | | - | | | 1 |
| | Regulatory Liabilities (a) | | | - | | | - | | | - |
Balance in AOCI as of March 31, 2010 | | $ | 2 | | $ | (13) | | $ | (11) |
| | | | | | | | | | | |
(a) | Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either |
| | current or noncurrent on the balance sheet. |
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | |
For the Nine Months Ended September 30, 2010 | |
| | | | Interest Rate | | | | |
| | | | and Foreign | | | | |
| Commodity | | Currency | | Total | |
| (in millions) | |
Balance in AOCI as of December 31, 2009 | | $ | (2 | ) | | $ | (13 | ) | | $ | (15 | ) |
Changes in Fair Value Recognized in AOCI | | | 2 | | | | (5 | ) | | | (3 | ) |
Amount of (Gain) or Loss Reclassified from AOCI | | | | | | | | | | | | |
to Income Statement/within Balance Sheet: | | | | | | | | | | | | |
Utility Operations Revenue | | | 1 | | | | - | | | | 1 | |
Other Revenue | | | (4 | ) | | | - | | | | (4 | ) |
Purchased Electricity for Resale | | | 3 | | | | - | | | | 3 | |
Interest Expense | | | - | | | | 3 | | | | 3 | |
Regulatory Assets (a) | | | 2 | | | | - | | | | 2 | |
Regulatory Liabilities (a) | | | - | | | | - | | | | - | |
Balance in AOCI as of September 30, 2010 | | $ | 2 | | | $ | (15 | ) | | $ | (13 | ) |
| | | | | | | | | | | | |
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | |
For the Nine Months Ended September 30, 2009 | |
| | | | | Interest Rate | | | | | |
| | | | | and Foreign | | | | | |
| Commodity | | Currency | | Total | |
| (in millions) | |
Balance in AOCI as of December 31, 2008 | | $ | 7 | | | $ | (29 | ) | | $ | (22 | ) |
Changes in Fair Value Recognized in AOCI | | | (9 | ) | | | 11 | | | | 2 | |
Amount of (Gain) or Loss Reclassified from AOCI | | | | | | | | | | | | |
to Income Statement/within Balance Sheet: | | | | | | | | | | | | |
Utility Operations Revenue | | | (13 | ) | | | - | | | | (13 | ) |
Other Revenue | | | (11 | ) | | | - | | | | (11 | ) |
Purchased Electricity for Resale | | | 24 | | | | - | | | | 24 | |
Interest Expense | | | - | | | | 4 | | | | 4 | |
Regulatory Assets (a) | | | 5 | | | | - | | | | 5 | |
Regulatory Liabilities (a) | | | (6 | ) | | | - | | | | (6 | ) |
Balance in AOCI as of September 30, 2009 | | $ | (3 | ) | | $ | (14 | ) | | $ | (17 | ) |
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or non-current on the balance sheet.
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our Condensed Consolidated Balance Sheets at September 30, 2010March 31, 2011 and December 31, 20092010 were:
Impact of Cash Flow Hedges on our Condensed Consolidated Balance Sheet | Impact of Cash Flow Hedges on our Condensed Consolidated Balance Sheet | | Impact of Cash Flow Hedges on our Condensed Consolidated Balance Sheet |
September 30, 2010 | | |
March 31, 2011 | | March 31, 2011 |
| | | | | | | | | | | | | | |
| | | Interest Rate | | | | | | | | | Interest Rate | | |
| | | and Foreign | | | | | | | | | and Foreign | | |
| Commodity | | Currency | | Total | | | | | Commodity | | Currency | | Total |
| (in millions) | | | | | (in millions) |
Hedging Assets (a) | $ | 16 | | $ | - | | $ | 16 | | Hedging Assets (a) | | $ | 14 | | $ | - | | $ | 14 |
Hedging Liabilities (a) | | (13 | ) | | (6 | ) | | (19 | ) | Hedging Liabilities (a) | | | (2) | | | (3) | | | (5) |
AOCI Gain (Loss) Net of Tax | | 2 | | | (15 | ) | | (13 | ) | AOCI Gain (Loss) Net of Tax | | | 8 | | 4 | | 12 |
Portion Expected to be Reclassified to Net | | Portion Expected to be Reclassified to Net | | | | | | | |
| | | | | | | | | | Income During the Next Twelve Months | | 5 | | (2) | | | 3 |
Portion Expected to be Reclassified to Net | | | | | | | | | | |
Income During the Next Twelve Months | | (1 | ) | | (4 | ) | | (5 | ) | |
| | | | | | | | | | | | | | | | | |
Impact of Cash Flow Hedges on our Condensed Consolidated Balance Sheet | Impact of Cash Flow Hedges on our Condensed Consolidated Balance Sheet | | Impact of Cash Flow Hedges on our Condensed Consolidated Balance Sheet |
December 31, 2009 | | |
December 31, 2010 | | December 31, 2010 |
| | | | | | | | | | | | | | | | | |
| | | | Interest Rate | | | | | | | | | | Interest Rate | | |
| | | | and Foreign | | | | | | | | | | and Foreign | | |
| Commodity | | Currency | | Total | | | | | Commodity | | Currency | | Total |
| (in millions) | | | | | (in millions) |
Hedging Assets (a) | $ | 8 | | $ | - | | $ | 8 | | Hedging Assets (a) | | $ | 13 | | $ | 25 | | $ | 38 |
Hedging Liabilities (a) | | (12 | ) | | (5 | ) | | (17 | ) | Hedging Liabilities (a) | | | (2) | | | (4) | | | (6) |
AOCI Gain (Loss) Net of Tax | | (2 | ) | | (13 | ) | | (15 | ) | AOCI Gain (Loss) Net of Tax | | | 7 | | 4 | | 11 |
Portion Expected to be Reclassified to Net | | Portion Expected to be Reclassified to Net | | | | | | | |
| | | | | | | | | | Income During the Next Twelve Months | | 3 | | (2) | | | 1 |
Portion Expected to be Reclassified to Net | | | | | | | | | | |
Income During the Next Twelve Months | | (2 | ) | | (4 | ) | | (6 | ) | |
| | Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on our Condensed Consolidated Balance Sheets. |
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 September 30, 2010,March 31, 2011, the maximum length of time that we are hedging (with contracts subject to the accounting guidance for “Derivatives and Hedging”) our exposure to variability in future cash flows related to forecasted transactions is 3938 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, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.
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), and a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads, we are obligated to post an additional 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 do not anticipate a downgrade below investment grade. The following table representsrepresents: (a) our aggregate fair value of such derivative contracts, (b) the amount of collateral we would have been required to post for all derivative and non-derivative contracts if our credit ratings had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of September 30, 2010March 31, 2011 and December 31, 2009:2010:
| September 30, | | December 31, | | | | March 31, | | December 31, |
| 2010 | | 2009 | | | | 2011 | | 2010 |
| (in millions) | | | | (in millions) |
Liabilities for Derivative Contracts with Credit Downgrade Triggers | | $ | 23 | | | $ | 10 | | Liabilities for Derivative Contracts with Credit Downgrade Triggers | | $ | 19 | | $ | 20 |
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post | | | 55 | | | | 34 | | |
Amount of Collateral AEP Subsidiaries Would Have Been | | Amount of Collateral AEP Subsidiaries Would Have Been | | | | | |
| | Required to Post | | 52 | | | 45 |
Amount Attributable to RTO and ISO Activities | | | 54 | | | | 29 | | Amount Attributable to RTO and ISO Activities | | 50 | | | 44 |
In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts. We do not anticipate a non-performance event under these provisions. The following table representsrepresents: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral we have posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering our contractual netting arrangements as of September 30, 2010March 31, 2011 and December 31, 2009:2010:
| September 30, | | December 31, | | | March 31, | | December 31, |
| 2010 | | 2009 | | | 2011 | | 2010 |
| (in millions) | | | (in millions) |
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements | | $ | 568 | | | $ | 567 | | |
Liabilities for Contracts with Cross Default Provisions Prior to Contractual | | | | | | |
Netting Arrangements | | | $ | 364 | | $ | 401 |
Amount of Cash Collateral Posted | | | 146 | | | | 15 | | | 29 | | | 81 |
Additional Settlement Liability if Cross Default Provision is Triggered | | | 241 | | | | 199 | | | 206 | | | 213 |
9.8. FAIR VALUE MEASUREMENTS
Fair Value Hierarchy and Valuation Techniques
The accounting guidance for “Fair Value Measurements and Disclosures” 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). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.
For our commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. We verify our price curves using these broker quotes and classify these fair values within Level 2 when substantially all of the fair value can be corroborated. We typically obtain multiple broker quotes, which are non-binding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, we average the quoted bid and ask prices. In certa incertain circumstances, we may discard a broker quote if it is a clear outlier. We use a historical correlation analysis
between the broker quoted location and the illiquid locations and iflocations. If the points are highly correlated, we include these locations within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Long-dated and illiquid complex or structured transactions and 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 as Level 3.
We utilize our trustee’s external pricing service in our estimate of the fair value of the underlying investments held in the nuclear trusts. Our investment managers review and validate the prices utilized by the trustee to determine fair value. We perform our own valuation testing to verify the fair values of the securities. We receive audit reports of our trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts.
Assets in the nuclear trusts, Cash and Cash Equivalents and Other Temporary Investments are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets. Fixed income securities do not trade on an exchange and do not have an official closing price. Pricing vendors calculate bond valuations using financial models and matrices. Fixed income securities are typically classified as Level 2 holdings because their valuation inputs are based on observable market data. Observable inputs used for valuing fixed income securities are benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark securities, bids, offers, reference data and economic events. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets.
Items classified as Level 2 are primarily investments in individual fixed income securities. These fixed income securities are valued using models with input data as follows:
| | | Type of Fixed Income Security |
| | | United States | | | | State and Local |
| Type of Input | | Government | | Corporate Debt | | Government |
| | | | | | | |
| Benchmark Yields | | X | | X | | X |
| Broker Quotes | | X | | X | | X |
| Discount Margins | | X | | X | | |
| Treasury Market Update | | X | | | | |
| Base Spread | | X | | X | | X |
| Corporate Actions | | | | X | | |
| Ratings Agency Updates | | | | X | | X |
| | | | | | | |
History | | | | | | X |
| Yield Adjustments | | X | | | | |
Fair Value Measurements of Long-term Debt
The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that we could realize in a current market exchange.
The book values and fair values of Long-term Debt as of September 30, 2010March 31, 2011 and December 31, 20092010 are summarized in the following table:
| | | September 30, 2010 | | December 31, 2009 |
| | | Book Value | | Fair Value | | Book Value | | Fair Value |
| | | (in millions) |
| Long-term Debt | | $ | 17,281 | | $ | 19,641 | | $ | 17,498 | | $ | 18,479 |
| | March 31, 2011 | | December 31, 2010 |
| | Book Value | | Fair Value | | Book Value | | Fair Value |
| | (in millions) |
Long-term Debt | | $ | 17,052 | | $ | 18,324 | | $ | 16,811 | | $ | 18,285 |
Fair Value Measurements of Other Temporary Investments
Other Temporary Investments include marketable securities that we intend to hold for less than one year, investments by our protected cell of EIS and funds held by trustees primarily for the repayment of debt.
The following is a summary of Other Temporary Investments:
| | | | | September 30, 2010 | |
| | | | | | | Gross | | Gross | | Estimated | |
| | | | | | | Unrealized | | Unrealized | | Fair |
| Other Temporary Investments | | Cost | | Gains | | Losses | | Value |
| | | | | (in millions) | |
| Restricted Cash (a) | | $ | 160 | | $ | - | | $ | - | | $ | 160 | |
| Fixed Income Securities: | | | | | | | | | | | | | |
| | Mutual Funds | | | 69 | | | 1 | | | - | | | 70 | |
| | Variable Rate Demand Notes | | | 73 | | | - | | | - | | | 73 | |
| Equity Securities - Mutual Funds | | | 18 | | | 5 | | | - | | | 23 | |
| Total Other Temporary Investments | | $ | 320 | | $ | 6 | | $ | - | | $ | 326 | |
| | | | | | | | | | | | | | | | |
| | | | | December 31, 2009 | |
| | | | | | | Gross | | Gross | | Estimated | |
| | | | | | | Unrealized | | Unrealized | | Fair | |
| Other Temporary Investments | | Cost | | Gains | | Losses | | Value | |
| | | | | (in millions) | |
| Restricted Cash (a) | | $ | 223 | | $ | - | | $ | - | | $ | 223 | |
| Fixed Income Securities: | | | | | | | | | | | | | |
| | Mutual Funds | | | 57 | | | - | | | - | | | 57 | |
| | Variable Rate Demand Notes | | | 45 | | | - | | | - | | | 45 | |
| Equity Securities: | | | | | | | | | | | | | |
| | Domestic | | | 1 | | | 15 | | | - | | | 16 | |
| | Mutual Funds | | | 18 | | | 4 | | | - | | | 22 | |
| Total Other Temporary Investments | | $ | 344 | | $ | 19 | | $ | - | | $ | 363 | |
| | | | | | | | | | | | | | | | |
| (a) | Primarily represents amounts held for the repayment of debt. |
| | | | March 31, 2011 | |
| | | | | | Gross | | Gross | | Estimated | |
| | | | | | Unrealized | | Unrealized | | Fair |
Other Temporary Investments | | Cost | | Gains | | Losses | | Value |
| | | | (in millions) | |
Restricted Cash (a) | | $ | 151 | | $ | - | | $ | - | | $ | 151 | |
Fixed Income Securities: | | | | | | | | | | | | | |
| Mutual Funds | | | 70 | | | - | | | - | | | 70 | |
| Variable Rate Demand Notes | | | 49 | | | - | | | - | | | 49 | |
Equity Securities - Mutual Funds | | | 18 | | | 8 | | | - | | | 26 | |
Total Other Temporary Investments | | $ | 288 | | $ | 8 | | $ | - | | $ | 296 | |
| | | | | | | | | | | | | | | |
| | | | December 31, 2010 | |
| | | | | | Gross | | Gross | | Estimated | |
| | | | | | Unrealized | | Unrealized | | Fair | |
Other Temporary Investments | | Cost | | Gains | | Losses | | Value | |
| | | | (in millions) | |
Restricted Cash (a) | | $ | 225 | | $ | - | | $ | - | | $ | 225 | |
Fixed Income Securities: | | | | | | | | | | | | | |
| Mutual Funds | | | 69 | | | - | | | - | | | 69 | |
| Variable Rate Demand Notes | | | 97 | | | - | | | - | | | 97 | |
Equity Securities - Mutual Funds | | | 18 | | | 7 | | | - | | | 25 | |
Total Other Temporary Investments | | $ | 409 | | $ | 7 | | $ | - | | $ | 416 | |
| | | | | | | | | | | | | | | |
(a) | Primarily represents amounts held for the repayment of debt. |
The following table provides the activity for our debt and equity securities within Other Temporary Investments for the three and nine months ended September 30, 2010March 31, 2011 and 2009:2010:
| Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended March 31, |
| 2010 | | 2009 | | 2010 | | 2009 | | 2011 | | 2010 |
| (in millions) | | (in millions) |
Proceeds From Investment Sales | | $ | 133 | | | $ | - | | | $ | 390 | | | $ | - | | $ | 196 | | $ | 241 |
Purchases of Investments | | | 192 | | | | 1 | | | | 413 | | | | 2 | | | 148 | | | 197 |
Gross Realized Gains on Investment Sales | | | - | | | | - | | | | 16 | | | | - | | | - | | | - |
Gross Realized Losses on Investment Sales | | | - | | | | - | | | | - | | | | - | | | - | | | - |
In June 2009,At March 31, 2011 and December 31, 2010, we recorded $9 million ($6 million, net of tax) of other-than-temporary impairments ofhad no Other Temporary Investments for equity investments of our protected cell captive insurance company.with an unrealized loss position. At September 30, 2010,March 31, 2011, the fair value of fixed income securities are primarily debt based mutual funds with short and intermediate maturities and variable rate demand notes. Mutual funds may be sold and do not contain maturity dates for an individual investment holder.dates.
Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal
Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow us to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include:
· | Acceptable investments (rated investment grade or above when purchased). |
· | Maximum percentage invested in a specific type of investment. |
· | Prohibition of investment in obligations of AEP or its affiliates. |
· | Withdrawals permitted only for payment of decommissioning costs and trust expenses. |
· | Target asset allocation is 50% fixed income and 50% equity securities. |
We maintain trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.
I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether the investor has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment, among other things, is based on whether the investor has the ability and intent to hold the investment to recover its value. Other-than-temporary impairments for investments in both debt a ndand equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and debt investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in thesethe trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. The gains, losses or other-than-temporary impairments shown below didConsequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw de commissioningdecommissioning funds.
The following is a summary of nuclear trust fund investments at September 30, 2010March 31, 2011 and December 31, 2009:2010:
| | | | September 30, 2010 | | December 31, 2009 |
| | | | Estimated | | Gross | | Other-Than- | | Estimated | | Gross | | Other-Than- |
| | | Fair | Unrealized | Temporary | Fair | Unrealized | Temporary |
| | | Value | Gains | Impairments | Value | Gains | Impairments |
| | | | (in millions) |
| Cash and Cash Equivalents | | $ | 30 | | $ | - | | $ | - | | $ | 14 | | $ | - | | $ | - |
| Fixed Income Securities: | | | | | | | | | | | | | | | | | | |
| | United States Government | | | 489 | | | 41 | | | (1) | | | 401 | | | 13 | | | (4) |
| | Corporate Debt | | | 65 | | | 5 | | | (2) | | | 57 | | | 5 | | | (2) |
| | State and Local Government | | | 308 | | | (7) | | | - | | | 369 | | | 8 | | | 1 |
| | Subtotal Fixed Income Securities | | 862 | | | 39 | | | (3) | | | 827 | | | 26 | | | (5) |
| Equity Securities - Domestic | | | 574 | | | 124 | | | (123) | | | 551 | | | 234 | | | (119) |
| Spent Nuclear Fuel and | | | | | | | | | | | | | | | | | | |
| | Decommissioning Trusts | | $ | 1,466 | | $ | 163 | | $ | (126) | | $ | 1,392 | | $ | 260 | | $ | (124) |
| | | March 31, 2011 | | December 31, 2010 |
| | | Estimated | | Gross | | Other-Than- | | Estimated | | Gross | | Other-Than- |
| | Fair | Unrealized | Temporary | Fair | Unrealized | Temporary |
| | Value | Gains | Impairments | Value | Gains | Impairments |
| | | (in millions) |
Cash and Cash Equivalents | | $ | 15 | | $ | - | | $ | - | | $ | 20 | | $ | - | | $ | - |
Fixed Income Securities: | | | | | | | | | | | | | | | | | | |
| United States Government | | | 473 | | | 18 | | | (1) | | | 461 | | | 23 | | | (1) |
| Corporate Debt | | | 55 | | | 3 | | | (2) | | | 59 | | | 4 | | | (2) |
| State and Local Government | | | 340 | | | 2 | | | - | | | 341 | | | (1) | | | - |
| Subtotal Fixed Income Securities | | 868 | | | 23 | | | (3) | | | 861 | | | 26 | | | (3) |
Equity Securities - Domestic | | | 676 | | | 226 | | | (113) | | | 634 | | | 183 | | | (123) |
Spent Nuclear Fuel and | | | | | | | | | | | | | | | | | | |
| Decommissioning Trusts | | $ | 1,559 | | $ | 249 | | $ | (116) | | $ | 1,515 | | $ | 209 | | $ | (126) |
The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2010March 31, 2011 and 2009:2010:
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
| | 2010 | | 2009 | | 2010 | | 2009 |
| | (in millions) |
| Proceeds From Investment Sales | $ | 495 | | $ | 113 | | $ | 1,087 | | $ | 524 |
| Purchases of Investments | | 512 | | | 129 | | | 1,129 | | | 571 |
| Gross Realized Gains on Investment Sales | | 1 | | | 1 | | | 7 | | | 10 |
| Gross Realized Losses on Investment Sales | | - | | | - | | | - | | | 1 |
| Three Months Ended March 31, |
| 2011 | | 2010 |
| (in millions) |
Proceeds From Investment Sales | $ | 288 | | $ | 232 |
Purchases of Investments | | 306 | | | 248 |
Gross Realized Gains on Investment Sales | | 5 | | | 5 |
Gross Realized Losses on Investment Sales | | 5 | | | - |
The adjusted cost of debt securities was $823$845 million and $801$835 million as of September 30, 2010March 31, 2011 and December 31, 2009,2010, respectively. The adjusted cost of equity securities was $450 million and $451 million as of March 31, 2011 and December 31, 2010, respectively.
The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at September 30, 2010March 31, 2011 was as follows:
| Fair Value | | Fair Value | |
| of Debt | | of Debt | |
| Securities | | Securities | |
| (in millions) | | (in millions) | |
Within 1 year | | $ | 13 | | | $ | 78 | |
1 year – 5 years | | | 346 | | | | 271 | |
5 years – 10 years | | | 267 | | | | 268 | |
After 10 years | | | 236 | | | | 251 | |
Total | | $ | 862 | | | $ | 868 | |
Fair Value Measurements of Financial Assets and Liabilities
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 September 30, 2010March 31, 2011 and December 31, 2009.2010. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” 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. There have not been any significant changes in AEP’s valuation techniques.
Assets and Liabilities Measured at Fair Value on a Recurring Basis | Assets and Liabilities Measured at Fair Value on a Recurring Basis | | Assets and Liabilities Measured at Fair Value on a Recurring Basis |
September 30, 2010 | | |
March 31, 2011 | | March 31, 2011 |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | | | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) | | Assets: | (in millions) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash and Cash Equivalents (a) | | $ | 922 | | | $ | - | | | $ | - | | | $ | 168 | | | $ | 1,090 | | Cash and Cash Equivalents (a) | $ | 417 | | $ | - | | $ | - | | $ | 208 | | $ | 625 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other Temporary Investments | | | | | | | | | | | | | | | | | | | | | Other Temporary Investments | | | | | | | | | | |
Restricted Cash (a) | | | 122 | | | | - | | | | - | | | | 38 | | | | 160 | | Restricted Cash (a) | | 103 | | | - | | | - | | | 48 | | 151 |
Fixed Income Securities: | | | | | | | | | | | | | | | | | | | | | Fixed Income Securities: | | | | | | | | | | | | | |
Mutual Funds | | | 70 | | | | - | | | | - | | | | - | | | | 70 | | |
Variable Rate Demand Notes | | | - | | | | 73 | | | | - | | | | - | | | | 73 | | |
| | Mutual Funds | | 70 | | | - | | | - | | | - | | 70 |
| | Variable Rate Demand Notes | | - | | | 49 | | | - | | | - | | 49 |
Equity Securities - Mutual Funds (b) | | | 23 | | | | - | | | | - | | | | - | | | | 23 | | Equity Securities - Mutual Funds (b) | | 26 | | | - | | | - | | | - | | | 26 |
Total Other Temporary Investments | | | 215 | | | | 73 | | | | - | | | | 38 | | | | 326 | | Total Other Temporary Investments | | 199 | | | 49 | | | - | | | 48 | | | 296 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | | | | | | | Risk Management Assets | | | | | | | | | | | | | |
Risk Management Commodity Contracts (c) (f) | | | 30 | | | | 1,876 | | | | 149 | | | | (1,365 | ) | | | 690 | | Risk Management Commodity Contracts (c) (f) | | 16 | | | 1,227 | | | 95 | | | (846) | | 492 |
Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | | Cash Flow Hedges: | | | | | | | | | | | | | |
Commodity Hedges (c) | | | 14 | | | | 12 | | | | - | | | | (10 | ) | | | 16 | | |
| | Commodity Hedges (c) | | 9 | | | 23 | | | - | | | (18) | | 14 |
Fair Value Hedges | | | - | | | | 7 | | | | - | | | | - | | | | 7 | | Fair Value Hedges | | - | | | 5 | | | - | | | - | | 5 |
Dedesignated Risk Management Contracts (d) | | | - | | | | - | | | | - | | | | 54 | | | | 54 | | Dedesignated Risk Management Contracts (d) | | - | | | - | | | - | | | 41 | | | 41 |
Total Risk Management Assets | | | 44 | | | | 1,895 | | | | 149 | | | | (1,321 | ) | | | 767 | | Total Risk Management Assets | | 25 | | | 1,255 | | | 95 | | | (823) | | | 552 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | | | | | | | | | | | | Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | | | | |
Cash and Cash Equivalents (e) | | | - | | | | 21 | | | | - | | | | 9 | | | | 30 | | Cash and Cash Equivalents (e) | | - | | | 5 | | | - | | | 10 | | 15 |
Fixed Income Securities: | | | | | | | | | | | | | | | | | | | | | Fixed Income Securities: | | | | | | | | | | | | | |
United States Government | | | - | | | | 489 | | | | - | | | | - | | | | 489 | | |
Corporate Debt | | | - | | | | 65 | | | | - | | | | - | | | | 65 | | |
State and Local Government | | | - | | | | 308 | | | | - | | | | - | | | | 308 | | |
Subtotal Fixed Income Securities | | | - | | | | 862 | | | | - | | | | - | | | | 862 | | |
| | United States Government | | - | | | 473 | | | - | | | - | | 473 |
| | Corporate Debt | | - | | | 55 | | | - | | | - | | 55 |
| | State and Local Government | | - | | | 340 | | | - | | | - | | | 340 |
| | | Subtotal Fixed Income Securities | | - | | 868 | | - | | - | | 868 |
Equity Securities - Domestic (b) | | | 574 | | | | - | | | | - | | | | - | | | | 574 | | Equity Securities - Domestic (b) | | 676 | | | - | | | - | | | - | | | 676 |
Total Spent Nuclear Fuel and Decommissioning Trusts | | | 574 | | | | 883 | | | | - | | | | 9 | | | | 1,466 | | Total Spent Nuclear Fuel and Decommissioning Trusts | | 676 | | | 873 | | | - | | | 10 | | | 1,559 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 1,755 | | | $ | 2,851 | | | $ | 149 | | | $ | (1,106 | ) | | $ | 3,649 | | Total Assets | $ | 1,317 | | $ | 2,177 | | $ | 95 | | $ | (557) | | $ | 3,032 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | | Liabilities: | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | | Risk Management Liabilities | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (c) (f) | | $ | 34 | | | $ | 1,773 | | | $ | 38 | | | $ | (1,573 | ) | | $ | 272 | | Risk Management Commodity Contracts (c) (f) | $ | 18 | | $ | 1,110 | | $ | 22 | | $ | (909) | | $ | 241 |
Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | | Cash Flow Hedges: | | | | | | | | | | | | |
Commodity Hedges (c) | | | 3 | | | | 20 | | | | - | | | | (10 | ) | | | 13 | | |
Interest Rate/Foreign Currency Hedges | | | - | | | | 6 | | | | - | | | | - | | | | 6 | | |
| | Commodity Hedges (c) | | 4 | | 16 | | | - | | | (18) | | 2 |
| | Interest Rate/Foreign Currency Hedges | | - | | | 3 | | | - | | | - | | 3 |
Fair Value Hedges | | Fair Value Hedges | | - | | | 1 | | | - | | | - | | | 1 |
Total Risk Management Liabilities | | $ | 37 | | | $ | 1,799 | | | $ | 38 | | | $ | (1,583 | ) | | $ | 291 | | Total Risk Management Liabilities | $ | 22 | | $ | 1,130 | | $ | 22 | | $ | (927) | | $ | 247 |
Assets and Liabilities Measured at Fair Value on a Recurring Basis | Assets and Liabilities Measured at Fair Value on a Recurring Basis | | Assets and Liabilities Measured at Fair Value on a Recurring Basis |
December 31, 2009 | | |
December 31, 2010 | | December 31, 2010 |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | | | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | | (in millions) | | Assets: | (in millions) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash and Cash Equivalents (a) | | $ | 427 | | | $ | - | | | $ | - | | | $ | 63 | | | $ | 490 | | Cash and Cash Equivalents (a) | $ | 170 | | $ | - | | $ | - | | $ | 124 | | $ | 294 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other Temporary Investments | | | | | | | | | | | | | | | | | | | | | Other Temporary Investments | | | | | | | | | | |
Restricted Cash (a) | | | 198 | | | | - | | | | - | | | | 25 | | | | 223 | | Restricted Cash (a) | | 184 | | | - | | | - | | | 41 | | 225 |
Fixed Income Securities: | | | | | | | | | | | | | | | | | | | | | Fixed Income Securities: | | | | | | | | | | | | | |
Mutual Funds | | | 57 | | | | - | | | | - | | | | - | | | | 57 | | |
Variable Rate Demand Notes | | | - | | | | 45 | | | | - | | | | - | | | | 45 | | |
Equity Securities (b): | | | | | | | | | | | | | | | | | | | | | |
Domestic | | | 16 | | | | - | | | | - | | | | - | | | | 16 | | |
Mutual Funds | | | 22 | | | | - | | | | - | | | | - | | | | 22 | | |
| | Mutual Funds | | 69 | | | - | | | - | | | - | | 69 |
| | Variable Rate Demand Notes | | - | | | 97 | | | - | | | - | | 97 |
Equity Securities - Mutual Funds (b) | | Equity Securities - Mutual Funds (b) | | 25 | | | - | | | - | | | - | | | 25 |
Total Other Temporary Investments | | | 293 | | | | 45 | | | | - | | | | 25 | | | | 363 | | Total Other Temporary Investments | | 278 | | | 97 | | | - | | | 41 | | | 416 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | | | | | | | Risk Management Assets | | | | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | | 8 | | | | 1,609 | | | | 72 | | | | (1,119 | ) | | | 570 | | Risk Management Commodity Contracts (c) (g) | | 20 | | | 1,432 | | | 112 | | | (1,013) | | 551 |
Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | | Cash Flow Hedges: | | | | | | | | | | | | | |
Commodity Hedges (c) | | | 1 | | | | 11 | | | | - | | | | (4 | ) | | | 8 | | |
| | Commodity Hedges (c) | | 11 | | | 17 | | | - | | | (15) | | 13 |
| | Interest Rate/Foreign Currency Hedges | | - | | | 25 | | | - | | | - | | 25 |
Fair Value Hedges | | Fair Value Hedges | | - | | | 7 | | | - | | | - | | 7 |
Dedesignated Risk Management Contracts (d) | | | - | | | | - | | | | - | | | | 25 | | | | 25 | | Dedesignated Risk Management Contracts (d) | | - | | | - | | | - | | | 46 | | | 46 |
Total Risk Management Assets | | | 9 | | | | 1,620 | | | | 72 | | | | (1,098 | ) | | | 603 | | Total Risk Management Assets | | 31 | | | 1,481 | | | 112 | | | (982) | | | 642 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | | | | | | | | | | | | Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | | | | |
Cash and Cash Equivalents (e) | | | - | | | | 3 | | | | - | | | | 11 | | | | 14 | | Cash and Cash Equivalents (e) | | - | | | 8 | | | - | | | 12 | | 20 |
Fixed Income Securities: | | | | | | | | | | | | | | | | | | | | | Fixed Income Securities: | | | | | | | | | | | | | |
United States Government | | | - | | | | 401 | | | | - | | | | - | | | | 401 | | |
Corporate Debt | | | - | | | | 57 | | | | - | | | | - | | | | 57 | | |
State and Local Government | | | - | | | | 369 | | | | - | | | | - | | | | 369 | | |
Subtotal Fixed Income Securities | | | - | | | | 827 | | | | - | | | | - | | | | 827 | | |
| | United States Government | | - | | | 461 | | | - | | | - | | 461 |
| | Corporate Debt | | - | | | 59 | | | - | | | - | | 59 |
| | State and Local Government | | - | | | 341 | | | - | | | - | | | 341 |
| | | Subtotal Fixed Income Securities | | - | | | 861 | | | - | | | - | | 861 |
Equity Securities - Domestic (b) | | | 551 | | | | - | | | | - | | | | - | | | | 551 | | Equity Securities - Domestic (b) | | 634 | | | - | | | - | | | - | | | 634 |
Total Spent Nuclear Fuel and Decommissioning Trusts | | | 551 | | | | 830 | | | | - | | | | 11 | | | | 1,392 | | Total Spent Nuclear Fuel and Decommissioning Trusts | | 634 | | | 869 | | | - | | | 12 | | | 1,515 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 1,280 | | | $ | 2,495 | | | $ | 72 | | | $ | (999 | ) | | $ | 2,848 | | Total Assets | $ | 1,113 | | $ | 2,447 | | $ | 112 | | $ | (805) | | $ | 2,867 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | | Liabilities: | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | | Risk Management Liabilities | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (c) (g) | | $ | 11 | | | $ | 1,415 | | | $ | 10 | | | $ | (1,205 | ) | | $ | 231 | | Risk Management Commodity Contracts (c) (g) | $ | 25 | | $ | 1,325 | | $ | 27 | | $ | (1,114) | | $ | 263 |
Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | | Cash Flow Hedges: | | | | | | | | | | | | |
Commodity Hedges (c) | | | - | | | | 16 | | | | - | | | | (4 | ) | | | 12 | | |
Interest Rate/Foreign Currency Hedges | | | - | | | | 5 | | | | - | | | | - | | | | 5 | | |
| | Commodity Hedges (c) | | 4 | | 13 | | | - | | | (15) | | 2 |
| | Interest Rate/Foreign Currency Hedges | | - | | 4 | | | - | | | - | | 4 |
Fair Value Hedges | | Fair Value Hedges | | - | | | 1 | | | - | | | - | | | 1 |
Total Risk Management Liabilities | | $ | 11 | | | $ | 1,436 | | | $ | 10 | | | $ | (1,209 | ) | | $ | 248 | | Total Risk Management Liabilities | $ | 29 | | $ | 1,343 | | $ | 27 | | $ | (1,129) | | $ | 270 |
| (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) | Amounts represent publicly traded equity securities and equity-based mutual funds. |
| (c) | Amounts in ''Other'' column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for ''Derivatives and Hedging.'' |
| (d) | Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for ''Derivatives and Hedging.'' At the time of the normal election, the MTM value was frozen and no longer fair valued. This MTM value will be amortized into revenues over the remaining life of the contracts. |
| (e) | Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 2 amounts primarily represent investments in money market funds. |
| (f) | The September 30, 2010 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $0 million in 2010, $0 million in periods 2011-2013 and ($4) million in periods 2014-2018; Level 2 matures $17 million in 2010, $58 million in periods 2011-2013, $9 million in periods 2014-2015 and $19 million in periods 2016-2028; Level 3 matures $6 million in 2010, $44 million in periods 2011-2013, $26 million in periods 2014-2015 and $35 million in periods 2016-2028. Risk management commodity contracts are substantially comprised of power contracts. |
| (g) | The DecemberMarch 31, 20092011 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures ($1) million in 2010, ($1)2011, $2 million in periods 2011-20132012-2014 and ($1)3) million in periods 2014-2015;2015-2018; Level 2 matures $65$12 million in 2010, $842011, $70 million in periods 2011-2013, $222012-2014, $17 million in periods 2014-20152015-2016 and $23$18 million in periods 2016-2028;2017-2028; Level 3 matures $17$8 million in 2011, $29 million in periods 2012-2014, $11 million in periods 2015-2016 and $25 million in periods 2017-2028. Risk management commodity contracts are substantially comprised of power contracts. |
(g) | The December 31, 2010 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures ($2) million in 2011, $2 million in periods 2012-2014 and ($5) million in periods 2015-2018; Level 2 matures $13 million in 2011, $66 million in periods 2012-2014, $12 million in periods 2015-2016 and $16 million in periods 2011-2013, $82017-2028; Level 3 matures $18 million in 2011, $24 million in periods 2014-2015 and $212012-2014, $16 million in periods 2016-2028.2015-2016 and $27 million in periods 2017-2028. Risk management commodity contracts are substantially comprised of power contracts. |
There have beenwere no transfers between Level 1 and Level 2 during the ninethree months ended September 30,March 31, 2011 and 2010.
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:
| | Net Risk | | | Net Risk | |
| | Management | | | Management | |
| | Assets | | | Assets | |
Three Months Ended September 30, 2010 | | (Liabilities) | | |
Three Months Ended March 31, 2011 | | | (Liabilities) | |
| | (in millions) | | | (in millions) | |
Balance as of June 30, 2010 | | | $ | 100 | | |
Balance as of December 31, 2010 | | | $ | 85 | |
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | | | (4 | ) | | | (2 | ) |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) | | | | | | | | | |
Relating to Assets Still Held at the Reporting Date (a) | | | | 23 | | | | (4 | ) |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | | | - | | | | - | |
Purchases, Issuances and Settlements (c) | | | | - | | | | (8 | ) |
Transfers into Level 3 (d) (h)(f) | | | | 5 | | | | - | |
Transfers out of Level 3 (e) (h)(f) | | | | (22 | ) | | | (8 | ) |
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | | | | 9 | | | | 10 | |
Balance as of September 30, 2010 | | | $ | 111 | | |
Balance as of March 31, 2011 | | | $ | 73 | |
| | Net Risk | |
| | Management | |
| | Assets | |
Nine Months Ended September 30, 2010 | | (Liabilities) | |
| | (in millions) | |
Balance as of December 31, 2009 | | | $ | 62 | |
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | | | 4 | |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) | | | | | |
Relating to Assets Still Held at the Reporting Date (a) | | | | 60 | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | | | - | |
Purchases, Issuances and Settlements (c) | | | | (18 | ) |
Transfers into Level 3 (d) (h) | | | | 14 | |
Transfers out of Level 3 (e) (h) | | | | (26 | ) |
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | | | | 15 | |
Balance as of September 30, 2010 | | | $ | 111 | |
| | Net Risk | |
| | Management | |
| | Assets | |
Three Months Ended September 30, 2009 | | (Liabilities) | |
| | (in millions) | |
Balance as of June 30, 2009 | | | $ | 67 | |
Realized (Gain) Loss Included in Net Income (or Changes in Net Assets) (a) | | | | (8 | ) |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) | | | | | |
Relating to Assets Still Held at the Reporting Date (a) | | | | 10 | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | | | - | |
Purchases, Issuances and Settlements | | | | - | |
Transfers in and/or out of Level 3 (f) | | | | 7 | |
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | | | | 28 | |
Balance as of September 30, 2009 | | | $ | 104 | |
| | Net Risk | | | Net Risk | |
| | Management | | | Management | |
| | Assets | | | Assets | |
Nine Months Ended September 30, 2009 | | (Liabilities) | | |
Three Months Ended March 31, 2010 | | | (Liabilities) | |
| | (in millions) | | | (in millions) | |
Balance as of December 31, 2008 | | | $ | 49 | | |
Realized (Gain) Loss Included in Net Income (or Changes in Net Assets) (a) | | | | (21 | ) | |
Balance as of December 31, 2009 | | | $ | 62 | |
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | | | 27 | |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) | | | | | | | | | |
Relating to Assets Still Held at the Reporting Date (a) | | | | 51 | | | | 24 | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | | | - | | | | - | |
Purchases, Issuances and Settlements(c) | | | | - | | | | (31 | ) |
Transfers in and/or out of Level 3 (f) | | | | (26 | ) | |
Transfers into Level 3 (d) (f) | | | | 15 | |
Transfers out of Level 3 (e) (f) | | | | 1 | |
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | | | | 51 | | | | 18 | |
Balance as of September 30, 2009 | | | $ | 104 | | |
Balance as of March 31, 2010 | | | $ | 116 | |
| | Included in revenues on our Condensed Consolidated Statements of Income. |
| (b) | Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. |
| (c) | Represents the settlement of risk management commodity contracts for the reporting period. |
| (d) | Represents existing assets or liabilities that were previously categorized as Level 2. |
| (e) | Represents existing assets or liabilities that were previously categorized as Level 3. |
| (f) | Represents existing assets or liabilitiesTransfers are recognized based on their value at the beginning of the reporting period 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.transfer occurred. |
| (g) | Relates to the net gains (losses) of those contracts that are not reflected on our Condensed Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets. |
| (h) | Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. |
10.9. INCOME TAXES
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 tax 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 2001. We have completed the exam for the years 2001 through 2006 and have issues that we are pursuing at the appeals level. TheIn April 2011, the IRS’s examination of the years 2007 and 2008 are currently under examination.was concluded with a settlement of all outstanding issues. The settlement will not have a material impact on net income, cash flows or financial condition. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal 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, managementManagement believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and the ultimate resolution of these audits will not 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.
For a discussion of the tax implications of our settlement with BOA and Enron, see “Enron Bankruptcy” section of Note 3.
Federal Tax Legislation
The Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act (Health Care Acts) were enacted in March 2010. The Health Care Acts amend tax rules so that the portion of employer health care costs that are reimbursed by the Medicare Part D prescription drug subsidy will no longer be deductible by the employer for federal income tax purposes effective for years beginning after December 31, 2012. Because of the loss of the future tax deduction, a reduction in the deferred tax asset related to the nondeductible OPEB liabilities accrued to date was recorded in March 2010. This reduction did not materially affect our cash flows or financial condition. For the ninethree months ended September 30,March 31, 2010, deferred tax assets decreased $56 million, partially of fsetoffset by recording net tax regulatory assets of $35 million in our jurisdictions with regulated operations, resulting in a decrease in net income of $21 million.
The Small Business Jobs Act (the Act) was enacted in September 2010. Included in this actthe Act was a one-year extension of the 50% bonus depreciation provision. The Tax Relief, Unemployment Insurance Reauthorization and the Job Creation Act of 2010 extended the life of research and development, employment and several energy tax credits originally scheduled to expire at the end of 2010. In addition, the Act extended the time for claiming bonus depreciation and increased the deduction to 100% for part of 2010 and 2011. The enacted provisionprovisions will not have a material impact on our net income or financial condition but will have a material favorable impact on cash flows.condition.
11.10. FINANCING ACTIVITIES
Long-term Debt | | | | | | | | | | | | |
| | | | | | | | | | | | |
Type of Debt | | September 30, 2010 | | | December 31, 2009 | | | March 31, 2011 | | | December 31, 2010 | |
| | (in millions) | | | (in millions) | |
Senior Unsecured Notes | | $ | 12,176 | | | $ | 12,416 | | | $ | 12,069 | | | $ | 11,669 | |
Pollution Control Bonds | | | 2,263 | | | | 2,159 | | | | 2,213 | | | | 2,263 | |
Notes Payable | | | 368 | | | | 326 | | | | 387 | | | | 396 | |
Securitization Bonds | | | 1,847 | | | | 1,995 | | | | 1,755 | | | | 1,847 | |
Junior Subordinated Debentures | | | 315 | | | | 315 | | | | 315 | | | | 315 | |
Spent Nuclear Fuel Obligation (a) | | | 265 | | | | 265 | | | | 265 | | | | 265 | |
Other Long-term Debt | | | 90 | | | | 88 | | | | 91 | | | | 91 | |
Unamortized Discount (net) | | | (43 | ) | | | (66 | ) | | | (43 | ) | | | (35 | ) |
Total Long-term Debt Outstanding | | | 17,281 | | | | 17,498 | | | | 17,052 | | | | 16,811 | |
Less Portion Due Within One Year | | | 1,286 | | | | 1,741 | | | | 1,421 | | | | 1,309 | |
Long-term Portion | | $ | 15,995 | | | $ | 15,757 | | | $ | 15,631 | | | $ | 15,502 | |
| (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 $307 million and $306 million at September 30, 2010March 31, 2011 and December 31, 2009, respectively,2010, are included in Spent Nuclear Fuel and Decommissioning Trusts on our Condensed Consolidated Balance Sheets. Sheets. |
Long-term debt and other securities issued, retired and principal payments made during the first ninethree months of 20102011 are shown in the tables below.
| | | | | | Principal | | | Interest | | |
| Company | | Type of Debt | | Amount | | | Rate | | Due Date |
| | | | | (in millions) | | (%) | | |
| Issuances: | | | | | | | | | | |
| APCo | | Senior Unsecured Notes | | $ | 300 | | | 3.40 | | 2015 |
| APCo | | Pollution Control Bonds | | | 18 | | | 4.625 | | 2021 |
| APCo | | Pollution Control Bonds | | | 50 | | | 5.375 | | 2038 |
| CSPCo | | Floating Rate Notes | | | 150 | | | Variable | | 2012 |
| I&M | | Notes Payable | | | 84 | | | 4.00 | | 2014 |
| OPCo | | Pollution Control Bonds | | | 86 | | | 3.125 | | 2015 |
| OPCo | | Pollution Control Bonds | | | 79 | | | 3.25 | | 2014 |
| OPCo | | Pollution Control Bonds | | | 39 | | | 2.875 | | 2014 |
| SWEPCo | | Senior Unsecured Notes | | | 350 | | | 6.20 | | 2040 |
| SWEPCo | | Pollution Control Bonds | | | 54 | | | 3.25 | | 2015 |
| PSO | | Notes Payable | | | 2 | | | 3.00 | | 2025 |
| Total Issuances | | | | $ | 1,212 | (a) | | | | |
| | | | | | | | | | | | |
| The above borrowing arrangements do not contain guarantees, collateral or dividend restrictions. |
| | | | | | | | | | | | |
| (a) | Amount indicated on the statement of cash flows of $1,201 million is net of issuance costs and premium or discount. |
| | | | | Principal | | | Interest | | |
Company | | Type of Debt | | Amount | | | Rate | | Due Date |
Issuances: | | | (in millions) | | (%) | | |
APCo | | Senior Unsecured Notes | | $ | 350 | | | 4.60 | | 2021 |
APCo | | Pollution Control Bonds | | | 65 | | | 2.00 | | 2012 |
APCo | | Pollution Control Bonds | | | 75 | (a) | | Variable | | 2036 |
APCo | | Pollution Control Bonds | | | 54 | (a) | | Variable | | 2042 |
APCo | | Pollution Control Bonds | | | 50 | (a) | | Variable | | 2036 |
APCo | | Pollution Control Bonds | | | 50 | (a) | | Variable | | 2042 |
I&M | | Pollution Control Bonds | | | 52 | (a) | | Variable | | 2021 |
I&M | | Pollution Control Bonds | | | 25 | (a) | | Variable | | 2019 |
OPCo | | Pollution Control Bonds | | | 50 | (a) | | Variable | | 2014 |
PSO | | Senior Unsecured Notes | | | 250 | | | 4.40 | | 2021 |
Total Issuances | | | | $ | 1,021 | (b) | | | | |
| | | | | | Principal | | | Interest | | |
| Company | | Type of Debt | | Amount Paid | | | Rate | | Due Date |
| | | | | (in millions) | | (%) | | |
| Retirements and | | | | | | | | | | |
| | Principal Payments: | | | | | | | | | | |
| AEP | | Senior Unsecured Notes | | $ | 490 | | | 5.375 | | 2010 |
| APCo | | Senior Unsecured Notes | | | 150 | | | 4.40 | | 2010 |
| APCo | | Pollution Control Bonds | | | 50 | | | 7.125 | | 2010 |
| I&M | | Notes Payable | | | 19 | | | 5.44 | | 2013 |
| OPCo | | Senior Unsecured Notes | | | 400 | | | Variable | | 2010 |
| OPCo | | Pollution Control Bonds | | | 79 | | | 7.125 | | 2010 |
| OPCo | | Pollution Control Bonds | | | 20 | | | 5.625 | | 2022 |
| OPCo | | Pollution Control Bonds | | | 20 | | | 5.625 | | 2023 |
| SWEPCo | | Pollution Control Bonds | | | 54 | | | Variable | | 2019 |
| | | | | | | | | | | | |
| Non-Registrant: | | | | | | | | | | |
| AEP Subsidiaries | | Notes Payable | | | 12 | | | Variable | | 2017 |
| AEP Subsidiaries | | Notes Payable | | | 5 | | | Variable | | 2011 |
| AEP Subsidiaries | | Notes Payable | | | 1 | | | 8.03 | | 2026 |
| AEGCo | | Senior Unsecured Notes | | | 7 | | | 6.33 | | 2037 |
| TCC | | Securitization Bonds | | | 32 | | | 5.56 | | 2010 |
| TCC | | Securitization Bonds | | | 54 | | | 4.98 | | 2010 |
| TCC | | Securitization Bonds | | | 24 | | | 5.96 | | 2013 |
| TCC | | Securitization Bonds | | | 37 | | | 4.98 | | 2013 |
| Total Retirements and | | | | | | | | | | |
| | Principal Payments | | | | $ | 1,454 | | | | | |
(a) | These pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year on our Condensed Consolidated Balance Sheets. |
(b) | Amount indicated on the statement of cash flows of $1,014 million is net of issuance costs and premium or discount. |
| | | | | Principal | | | Interest | | |
Company | | Type of Debt | | Amount Paid | | | Rate | | Due Date |
Retirements and | | | (in millions) | | (%) | | |
| Principal Payments: | | | | | | | | | | |
APCo | | Pollution Control Bonds | | $ | 75 | | | Variable | | 2036 |
APCo | | Pollution Control Bonds | | | 54 | | | Variable | | 2042 |
APCo | | Pollution Control Bonds | | | 50 | | | Variable | | 2042 |
APCo | | Pollution Control Bonds | | | 50 | | | Variable | | 2036 |
I&M | | Pollution Control Bonds | | | 52 | | | Variable | | 2021 |
I&M | | Pollution Control Bonds | | | 25 | | | Variable | | 2019 |
I&M | | Notes Payable | | | 5 | | | Variable | | 2015 |
OPCo | | Pollution Control Bonds | | | 65 | | | Variable | | 2036 |
OPCo | | Pollution Control Bonds | | | 50 | | | Variable | | 2014 |
OPCo | | Pollution Control Bonds | | | 50 | | | Variable | | 2014 |
PSO | | Senior Unsecured Notes | | | 200 | | | 6.00 | | 2032 |
| | | | | | | | | | | |
Non-Registrant: | | | | | | | | | | |
AEP Subsidiaries | | Notes Payable | | | 5 | | | Variable | | 2017 |
AEGCo | | Senior Unsecured Notes | | | 4 | | | 6.33 | | 2037 |
TCC | | Securitization Bonds | | | 34 | | | 5.96 | | 2013 |
TCC | | Securitization Bonds | | | 58 | | | 4.98 | | 2013 |
Total Retirements and | | | | | | | | | | |
| Principal Payments | | | | $ | 777 | | | | | |
In October 2010, I&MApril 2011, APCo retired $150$250 million of 6%5.55% Senior Unsecured Notes due in 2032.
In November 2010, OPCo retired $200 million of 5.3% Senior Unsecured Notes due in 2010.2011.
In April 2011, I&M retired $30 million of Notes Payable related to DCC Fuel.
As of September 30, 2010,March 31, 2011, trustees held, on our behalf, $303$418 million of our reacquired auction-rate tax-exempt long-term debt.Pollution Control Bonds.
Dividend Restrictions
Parent Restrictions
The holders of our common stock are entitled to receive the dividends declared by our Board of Directors provided funds are legally available for such dividends. Our income derives from our common stock equity in the earnings of our utility subsidiaries.
Pursuant to the leverage restrictions in our credit agreements, we must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and other capitalcapitalization is contractually defined in the credit agreements. None of AEP’s retained earnings were restricted for the purpose of the payment of dividends.
We have issued $315 million of Junior Subordinated Debentures. The debentures will mature on March 1, 2063, subject to extensions to no later than March 1, 2068.2068, and are callable at par any time on or after March 1, 2013. We have the option to defer interest payments on the debentures 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 do not anticipate any deferral of those interest payments in the foreseeable future.
Utility Subsidiaries’ Restrictions
Various financing arrangements, charter provisions and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends. Specifically, most of our public utility subsidiaries have revolving credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%. At DecemberMarch 31, 2009,2011, the amount of restricted net assets of AEP’s subsidiaries that may not be distributed to Parent in the form of a loan, advance or dividend was approximately $7 billion.
The Federal Power Act prohibits the utility subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the par value of the common stock multiplied by the number of shares outstanding. This restriction does not limit the ability of the utility subsidiaries to pay dividends out of retained earnings.
Short-term Debt | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Our outstanding short-term debt was as follows: | | | | | | | | | | | |
| | | | September 30, 2010 | | December 31, 2009 |
| | | | Outstanding | | Interest | | Outstanding | | Interest |
| Type of Debt | Amount | Rate (a) | | Amount | Rate (a) |
| | | (in millions) | | | | | (in millions) | | | |
| Securitized Debt for Receivables (b) | | $ | 750 | | 0.36 | % | | $ | - | | - | % |
| Commercial Paper | | | 713 | | 0.46 | % | | | 119 | | 0.26 | % |
| Line of Credit – Sabine Mining Company (c) | | | 3 | | 2.20 | % | | | 7 | | 2.06 | % |
| Total Short-term Debt | | $ | 1,466 | | | | | $ | 126 | | | |
| | | | | | | | | | | | | |
Our outstanding short-term debt was as follows: | | | | | | | | | | | |
| | | March 31, 2011 | | December 31, 2010 |
| | | Outstanding | | Interest | | Outstanding | | Interest |
Type of Debt | Amount | Rate (a) | | Amount | Rate (a) |
| | (in millions) | | | | | (in millions) | | | |
Securitized Debt for Receivables (b) | | $ | 620 | | 0.30 | % | | $ | 690 | | 0.31 | % |
Commercial Paper | | | 813 | | 0.48 | % | | | 650 | | 0.52 | % |
Line of Credit – Sabine Mining Company (c) | | | - | | - | % | | | 6 | | 2.15 | % |
Total Short-term Debt | | $ | 1,433 | | | | | $ | 1,346 | | | |
| (b) | Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance. See ''ASU 2009-16 'Transfers and Servicing' '' section of Note 2. |
| (c) | Sabine Mining Company is a consolidated variable interest entity. This line of credit does not reduce available liquidity under AEP's credit facilities. |
Credit Facilities
We have credit facilities totaling $3 billion to support our commercial paper program. The facilities are structured as two $1.5 billion credit facilities, ofunder which $750 millionwe may be issued under one credit facility as letters of credit. In June 2010, we terminated one of the $1.5 billion facilities that was scheduled to mature in March 2011 and replaced it with a new $1.5 billion credit facility which matures in 2013 and allows for the issuance ofissue up to $600 million$1.35 billion as letters of credit. As of September 30, 2010,March 31, 2011, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $125$124 million.
In June 2010,March 2011, we reduced the $627terminated a $478 million credit agreement that was scheduled to $478 million. Under the facility, we may issue letters of credit. As of September 30, 2010, $477mature in April 2011 and was used to support $472 million of letters of credit were issued by subsidiaries under this credit agreement to support variable rate Pollution Control Bonds. In March 2011, we remarketed $357 million of variable rate Pollution Control Bonds using bilateral letters of credit for $361 million to support the remarketed Pollution Control Bonds. The remaining $115 million of Pollution Control Bonds were reacquired and are held by trustees.
Securitized Accounts Receivable – AEP Credit
AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. Prior to January 1, 2010, this transaction constituted a sale of receivables in accordance with the accounting guidance for “Transfers and Servicing,” allowing the receivables to be removed from our Condensed Consolidated Balance Sheet. See “ASU 2009-16 ‘Transfers and Servicing’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010 whereby such future transactions do not constitute a sale of receivables and will be accounted for as financings. AEP Credit continues to service the receivables. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase our operating companies’ receivables and accelerate AEP Credit’s cash collections.
In July 2010, AEP Credit renewed its receivables securitization agreement. The agreement provides a commitment of $750 million from bank conduits to finance receivables from AEP Credit. A commitment of $375 million expires in July 2011 and the remaining commitment of $375 million expires in July 2013.
Accounts receivable information for AEP Credit is as follows:
| | | | Three Months Ended | | Nine Months Ended | |
| | | | September 30, | | September 30, | |
| | | | 2010 | | 2009 | | 2010 | | 2009 | |
| | | (dollars in millions) | |
| Proceeds from Sale of Accounts Receivable | | $ | N/A | | $ | 1,814 | | $ | N/A | | $ | 5,314 | |
| Loss on Sale of Accounts Receivable | | | N/A | | | - | | | N/A | | | 2 | |
| Average Variable Discount Rate on Sale of | | | | | | | | | | | | | |
| | Accounts Receivable | | | N/A | | | 0.38 | % | | N/A | | | 0.68 | % |
| Effective Interest Rates on Securitization of | | | | | | | | | | | | | |
| | Accounts Receivable | | | 0.41 | % | | N/A | | | 0.32 | % | | N/A | |
| Net Uncollectible Accounts Receivable | | | | | | | | | | | | | |
| | Written Off | | | 9 | | | 9 | | | 16 | | | 23 | |
| | | Three Months Ended | |
| | | March 31, | |
| | | 2011 | | 2010 | |
| | (dollars in millions) | |
Effective Interest Rate on Securitization of Accounts Receivable | | | 0.31 | % | | 0.23 | % |
Net Uncollectible Accounts Receivable Written Off | | $ | 11 | | $ | 4 | |
| | September 30, | | | December 31, | |
| | 2010 | | | 2009 | |
| | (in millions) | |
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts | | $ | 1,002 | | | $ | 160 | |
Deferred Revenue from Servicing Accounts Receivable | | | N/A | | | | 1 | |
Retained Interest if 10% Adverse Change in Uncollectible Accounts | | | N/A | | | | 158 | |
Retained Interest if 20% Adverse Change in Uncollectible Accounts | | | N/A | | | | 156 | |
Total Principal Outstanding | | | 750 | | | | 656 | |
Derecognized Accounts Receivable | | | N/A | | | | 631 | |
Delinquent Securitized Accounts Receivable | | | 49 | | | | 29 | |
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable | | | 27 | | | | 20 | |
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable | | | 301 | | | | 376 | |
| | | | | | | | |
N/A = Not Applicable | | | | | | | | |
| | | March 31, | | December 31, |
| | | 2011 | | 2010 |
| | | (in millions) |
Accounts Receivable Retained Interest and Pledged as Collateral | | | | | | |
| Less Uncollectible Accounts | | $ | 893 | | $ | 923 |
Total Principal Outstanding | | | 620 | | | 690 |
Delinquent Securitized Accounts Receivable | | | 42 | | | 50 |
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable | | | 21 | | | 26 |
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable | | | 297 | | | 354 |
Customer accounts receivable retained and securitized for our operating companies are managed by AEP Credit. AEP Credit’s delinquent customer accounts receivable represents accounts greater than 30 days past due.
12.11. COST REDUCTION INITIATIVES
In April 2010, we began initiatives to decrease both labor and non-labor expenses with a goal of achieving significant reductions in operation and maintenance expenses. A total of 2,461 positions were eliminated across the AEP System as a result of process improvements, streamlined organizational designs and other efficiencies. Most of the affected employees terminated employment May 31, 2010. The severance program providesprovided two weeks of base pay for every year of service along with other severance benefits.
We recorded a charge to Other Operation expense of $293 million in the second quarter of 2010 primarily related to the headcount reduction initiatives.
| | Total | |
| | (in millions) | |
Incurred | | $ | 293 | |
Settled | | | 265 | |
Adjustments | | | (3 | ) |
Remaining Balance at September 30, 2010 | | $ | 25 | |
These costs relaterelated primarily to severance benefits. TheyWe do not expect additional costs to be incurred related to this initiative.
| | Total |
| | (in millions) |
Balance as of December 31, 2010 | | $ | 17 |
Incurred | | | - |
Settled | | | (5) |
Adjustments | | | (1) |
Balance as of March 31, 2011 | | $ | 11 |
The remaining accruals are included primarily in Other Operation on the income statement and Other Current Liabilities on the balance sheet. Approximately 99% of the expense was within the Utility Operations segment.Condensed Consolidated Balance Sheets.
APPALACHIAN POWER COMPANY
AND SUBSIDIARIES
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS | |
| | | |
RESULTS OF OPERATIONS | | | |
| | | |
Third Quarter of 2010 Compared to Third Quarter of 2009 | |
| | | |
Reconciliation of Third Quarter of 2009 to Third Quarter of 2010 | |
Net Income | |
(in millions) | |
| | | |
Third Quarter of 2009 | | $ | 27 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins | | | 44 | |
Off-system Sales | | | 3 | |
Other Revenues | | | (1 | ) |
Total Change in Gross Margin | | | 46 | |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | (9 | ) |
Depreciation and Amortization | | | (7 | ) |
Taxes Other Than Income Taxes | | | (2 | ) |
Carrying Costs Income | | | 1 | |
Other Income | | | (2 | ) |
Total Expenses and Other | | | (19 | ) |
| | | | |
Income Tax Expense | | | (4 | ) |
| | | | |
Third Quarter of 2010 | | $ | 50 | |
APPALACHIAN POWER COMPANY AND SUBSIDIARIESMANAGEMENT’S DISCUSSION AND ANALYSIS
EXECUTIVE OVERVIEW
Regulatory Activity
Virginia Regulatory Activity
In March 2011, APCo filed a generation and distribution base rate request with the Virginia SCC to increase annual base rates by $126 million based upon an 11.65% return on common equity to be effective no later than February 2012. The return on common equity includes a requested 0.5% renewable portfolio standards incentive as allowed by law. APCo proposed to mitigate the requested base rate increase by $51 million by maintaining current depreciation rates until the next biennial filing. If approved, APCo’s net base rate increase would be $75 million. See “Virginia Biennial Base Rate Case” section of Note 2.
West Virginia Regulatory Activity
In March 2011, the WVPSC modified and approved a settlement agreement which increased annual base rates by approximately $46 million based upon a 10% return on common equity. The order also resulted in a pretax write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility in the first quarter of 2011. See “Mountaineer Carbon Capture and Storage Project Product Validation Facility” section below. In addition, the WVPSC allowed APCo to defer and amortize $18 million of previously expensed 2009 incremental storm expenses and $14 million of costs that were previously expensed related to the 2010 cost reduction initiative, each over a period of seven years. See “2010 West Virginia Base Rate Case” section of Note 2.
In a November 2009 proceeding established by the WVPSC to explore options to meet WPCo's future power supply requirements, the WVPSC issued an order approving a joint stipulation among APCo, WPCo, the WVPSC staff and the Consumer Advocate Division. The order approved the recommendation of the signatories to the stipulation that WPCo merge into APCo and be supplied from APCo's existing power resources. Merger approvals from the WVPSC, Virginia SCC and the FERC are required. No merger approval filings have been made. See “WPCo Merger with APCo” section of Note 2.
Mountaineer Carbon Capture and Storage Project Product Validation Facility (PVF)
APCo and ALSTOM Power, Inc., an unrelated third party, jointly constructed a CO2 capture validation facility, which was placed into service in September 2009. APCo also constructed and owns the necessary facilities to store the CO2. In APCo’s May 2010 West Virginia base rate filing, APCo requested rate base treatment of the PVF including recovery of the related asset retirement obligation regulatory asset amortization and accretion. In March 2011, a WVPSC order denied the request for rate base treatment of the PVF largely due to its experimental operation. The base rate order provided that should APCo construct a commercial scale carbon capture and sequestration (CCS) facility, only the West Virginia portion of the PVF costs, based on load sharing among certain AEP operating companies, may be considered used and useful plant in service and included in future rate base. As a result, APCo recorded a pretax write-off of $41 million ($26 million net of tax) in the first quarter of 2011. As of March 31, 2011, APCo has recorded a noncurrent regulatory asset of $19 million related to the PVF. If APCo cannot recover its remaining investment in and accretion expenses related to the PVF, it would reduce future net income and cash flows. See “Mountaineer Carbon Capture and Storage Project” section of Note 2.
Carbon Capture and Sequestration Project with the Department of Energy (DOE)
During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale CCS facility under consideration at the Mountaineer Plant. AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project. The DOE will fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million. A Front-End Engineering and Design (FEED) study, scheduled for completion during the third quarter of 2011, will refine the total cost estimate for the CCS facility. Results from the FEED study will be evaluated by management before any decision is made to seek the necessary regulatory approvals to build the CCS facility. As of March 31, 2011, APCo has incurred $25 million in
total costs and has received $7 million of DOE eligible funding resulting in a net $18 million balance included in Construction Work In Progress on the Condensed Consolidated Balance Sheets. Upon the completion of the FEED study and the expected reimbursement of eligible cash expenditures, principally from the DOE, APCo expects a net investment of approximately $13 million. If APCo is unable to recover the costs of the CCS project, it would reduce future net income and cash flows. See “Mountaineer Carbon Capture and Storage Project” section of Note 2.
Proposed Acquisition of Dresden Plant
During the first quarter of 2011, APCo and AEGCo filed with the Virginia and West Virginia regulatory commissions seeking approval for APCo’s purchase of the partially completed Dresden Plant from AEGCo at cost. The Dresden Plant is located near Dresden, Ohio and is a natural gas, combined cycle power plant. AEGCo resumed construction in the first quarter of 2011 following a suspension in 2009 due to economic conditions. When completed, the Dresden Plant will have a generating capacity of 580 MW.
Litigation and Environmental Issues
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 resolution will be or the timing and amount of any loss, fine or penalty may be. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss 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 2010 Annual Report. Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 143. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.
See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 201 for additional discussion of relevant factors.
RESULTS OF OPERATIONS | | | | | | |
| | | | | | |
KWH Sales/Degree Days | | | | | | |
Summary of KWH Energy Sales |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in millions of KWH) |
Retail: | | | | | |
| Residential | | 3,959 | | | 4,528 |
| Commercial | | 1,698 | | | 1,787 |
| Industrial | | 2,619 | | | 2,463 |
| Miscellaneous | | 210 | | | 222 |
Total Retail | | 8,486 | | | 9,000 |
| | | | | |
Wholesale | | 1,827 | | | 1,703 |
| | | | | |
Total KWHs | | 10,313 | | | 10,703 |
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.
Summary of Heating and Cooling Degree Days |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in degree days) |
| | | | | | |
Actual - Heating (a) | | 1,330 | | | 1,577 |
Normal - Heating (b) | | 1,337 | | | 1,399 |
| | | | | | |
Actual - Cooling (c) | | 6 | | | - |
Normal - Cooling (b) | | 6 | | | 6 |
| | | | | | |
(a) | Eastern 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 cooling degree days are calculated on a 65 degree temperature base. |
First Quarter of 2011 Compared to First Quarter of 2010 | |
| | | |
Reconciliation of First Quarter of 2010 to First Quarter of 2011 | |
Net Income | |
(in millions) | |
| | | |
First Quarter of 2010 | | $ | 70 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins | | | (60 | ) |
Off-system Sales | | | 1 | |
Transmission Revenue | | | 2 | |
Total Change in Gross Margin | | | (57 | ) |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | 8 | |
Depreciation and Amortization | | | 8 | |
Taxes Other Than Income Taxes | | | (1 | ) |
Carrying Costs Income | | | (2 | ) |
Interest Expense | | | (1 | ) |
Total Expenses and Other | | | 12 | |
| | | | |
Income Tax Expense | | | 14 | |
| | | | |
First Quarter of 2011 | | $ | 39 | |
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 increased $44decreased $60 million primarily due to the following: |
| · | A $46 million decrease primarily due to a 13% decrease in residential usage, a 5% decrease in commercial usage and lower retail rates. |
| · | A $31$23 million increasedecrease in rate relief primarily due to an increase in the recoveryexpiration of E&R costscost recovery in Virginia construction financing costsand the implementation of higher interim rates in West Virginia in January and costs related to the Transmission Rate Adjustment Clause in Virginia.February 2010. This increasedecrease in retail margins had corresponding increasesdecreases of $15$17 million related to riders/trackers recognized in other expense items discussed below. |
| | · | A $16 million increase in residential usage primarily due to a 47% increase in cooling degree days. |
| | These increasesdecreases were partially offset by: |
| | · | A $5$21 million decrease in industrial sales primarilyincrease due to the decreased load for APCo’s largest customer, Century Aluminum. |
Total Expenses and Other and Income Tax Expense changed between years as follows:
| · | Other Operation and Maintenance expenses increased $9 million primarily due to the reduction of under-recovery of transmission costs resulting from the implementation of the Transmission Rate Adjustment Clause in Virginia in December 2009.
|
| · | Depreciation and Amortization expenses increased $7 million primarily due to a greater depreciation base resulting from environmental upgrades at the Amos Plant and the amortization of carrying charges which are being collected through the Virginia E&R surcharges.
|
| · | Income Tax Expense increased $4 million primarily due to an increase in pretax book income, partially offset by the regulatory accounting treatment of state income taxes and other book/tax differences which are accounted for on a flow-through basis.
|
Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009 |
| | | | |
Reconciliation of Nine Months Ended September 30, 2009 to Nine Months Ended September 30, 2010 |
Net Income |
(in millions) |
| | | | |
Nine Months Ended September 30, 2009 | | $ | 131 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins | | | 100 | |
Off-system Sales | | | 5 | |
Other Revenues | | | (3) | |
Total Change in Gross Margin | | | 102 | |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | (113) | |
Depreciation and Amortization | | | (23) | |
Taxes Other Than Income Taxes | | | (10) | |
Carrying Costs Income | | | 7 | |
Other Income | | | (4) | |
Interest Expense | | | (3) | |
Total Expenses and Other | | | (146) | |
| | | | |
Income Tax Expense | | | 14 | |
| | | | |
Nine Months Ended September 30, 2010 | | $ | 101 | |
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 $100 million primarily due to the following:
|
| | · | A $106 million increase in rate relief primarily due to the impact of the Virginia interim rate increase implemented in December 2009 and increases in the recoveries of E&R costs in Virginia, costs related to the Transmission Rate Adjustment Clause in Virginia and construction financing costs in West Virginia. This increase in retail margins had corresponding increases of $48 million related to riders/trackers recognized in other expense items discussed below. |
| | · | A $33 million increase in residential usage primarily due to a 45% increase in cooling degree days. |
| | These increases were partially offset by: |
| | · | A $19 million decrease in industrial sales primarily due to the decreased load for APCo’s largest customer, Century Aluminum. |
| | · | An $18 million decrease due to higherlower capacity settlement expenses under the Interconnection Agreement net of recovery in West Virginia and environmental deferrals in Virginia. |
| · | Margins from Off-system Sales increased $5 million primarily due to increased prices and higher physical sales volumes, partially offset by lower trading and marketing margins.
|
Total Expenses and Other and Income Tax Expense changed between years as follows:
| · | Other Operation and Maintenance expenses increased $113decreased $8 million primarily due to the following: |
| | · | A $54$32 million decrease due to the deferral of storm costs and costs related to 2010 cost reduction initiatives. These costs were deferred as a result of the approved modified settlement agreement of APCo’s West Virginia base rate case in March 2011. |
| · | A $6 million decrease in employee-related expenses. |
| · | A $6 million decrease primarily due to lower overhead line maintenance expenses. |
| · | A $5 million decrease in maintenance expenses in 2011 resulting primarily from a 2010 planned outage at the Amos Plant. |
| These decreases were partially offset by: |
| · | A $41 million increase due to the write-off of APCo’s Virginia sharea portion of the Mountaineer Carbon Capture and Storage Project which wasProduct Validation Facility as denied for recovery by the Virginia SCC. | |
| | · | A $51 million increase due to expenses related to the cost reduction initiatives. | |
| | · | A $19 million increase primarily due to the reduction of under-recovery of transmission costs resulting from the implementation of the Transmission Rate Adjustment ClauseWVPSC in Virginia in December 2009. | |
| | These increases were partially offset by: |
| | · | A $25 million decrease due to the deferral of 2009 storm costs as allowed by the Virginia SCC in the second quarter of 2010. | March 2011. |
| · | Depreciation and Amortization expenses increased $23decreased $8 million primarily due to a greaterthe expiration of E&R amortization of deferred carrying costs in Virginia, partially offset by an increased depreciation base resulting from environmental upgrades at the Amos Plant and the amortization of carrying charges which are being collected through the Virginia E&R surcharges. |
| · | Taxes Other Than Income Taxes increased $10 million primarily due to recording a West Virginia franchise tax audit settlement and additional employer payroll taxes incurred related to the cost reduction initiatives.
|
| · | Carrying Costs Income increased $7 million primarily due to increased environmental deferrals in Virginia.Plant.
|
| · | Income Tax Expense decreased $14 million primarily due to a decrease in pretax book income, partially offset by other book/tax differences which are accounted for on a flow-through basis.income. |
FINANCIAL CONDITION
LIQUIDITY
APCo participates in the Utility Money Pool, which provides access to AEP’s liquidity. APCo has $250 million of Senior Unsecured Notes that matured in April 2011. APCo relies upon ready access to capital markets, 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 beginning on page 230201 for additional discussion of liquidity.
Credit Ratings
Downgrades inAPCo’s ultimate access to capital markets may depend on its credit ratingsratings. In addition, a credit rating downgrade of APCo by one of the rating agencies could increase APCo’s borrowing costs. Failure to maintain investment grade ratings may constrain APCo’s ability to participate in the Utility Money Pool or the amount of APCo’s receivables securitized by AEP Credit. Counterparty concerns about APCo’s credit quality could subject APCo to additional collateral demands under adequate assurance clauses under derivative and non-derivative energy contracts.
CASH FLOW
Cash flows for the ninethree months ended September 30,March 31, 2011 and 2010 and 2009 were as follows:
| | 2010 | | | 2009 | | | | 2011 | | 2010 |
| | (in thousands) | | | | (in thousands) |
Cash and Cash Equivalents at Beginning of Period | | $ | 2,006 | | | $ | 1,996 | | Cash and Cash Equivalents at Beginning of Period | | $ | 951 | | $ | 2,006 |
Net Cash Flows from (Used for) Operating Activities | | | 567,464 | | | | (53,712 | ) | |
Net Cash Flows from Operating Activities | | Net Cash Flows from Operating Activities | | 250,841 | | | 178,522 |
Net Cash Flows Used for Investing Activities | | | (363,246 | ) | | | (406,707 | ) | Net Cash Flows Used for Investing Activities | | (492,622) | | | (167,978) |
Net Cash Flows from (Used for) Financing Activities | | | (204,023 | ) | | | 460,237 | | Net Cash Flows from (Used for) Financing Activities | | | 243,214 | | | (10,308) |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 195 | | | | (182 | ) | |
Net Increase in Cash and Cash Equivalents | | Net Increase in Cash and Cash Equivalents | | | 1,433 | | | 236 |
Cash and Cash Equivalents at End of Period | | $ | 2,201 | | | $ | 1,814 | | Cash and Cash Equivalents at End of Period | | $ | 2,384 | | $ | 2,242 |
Operating Activities
Net Cash Flows from Operating Activities were $567$251 million in 2010.2011. APCo produced Net Income of $101$39 million during the period and had noncash expense items of $227$69 million for Depreciation and Amortization and $53$61 million for Deferred Income Taxes. APCo contributed $32 million to the qualified pension trust. 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 $133 million inflow from Fuel, Materials and Supplies was primarily due to a reduction in fuel inventory and a decrease in the average cost of c oal per ton. The $114 million outflow from Accounts Payable was primarily due to payments for storm costs accrued in fourth quarter of 2009 and decreased purchases of energy from the system pool. The $107 million inflow from Accrued Taxes, Net includes a third quarter 2010 income tax refund of $170 million as a result of a federal net income tax operating loss in 2009 that was carried back to 2007 and 2008. Items contributing to the net income tax operating loss include bonus depreciation and the favorable impact of a change in tax accounting method related to units of property. The $94$110 million inflow from Accounts Receivable, Net was primarily due to a decrease in accrued unbilled revenues due to usual seasonal fluctuations and timing of settlements of receivables from affiliated companies. The $71 million outflow from Accounts Payable was primarily due to decreased energy purchases and reduced operation and maintenance expenses. The $62 million inflow from Fuel, Materials and Supplies was primarily due to a reduction in fuel inventory and a decrease in the average cost of coal per ton. The $32 million outflow from Accrued Taxes, Net was primarily the result of a decrease in federal income tax accruals.
Net Cash Flows Used forfrom Operating Activities were $54$179 million in 2009.2010. APCo produced Net Income of $131$70 million during the period and hada noncash expense itemsitem of $229 million for Deferred Income Taxes and $204$77 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 $160 million outflow from Fuel, Materials and Supplies was primarily due to an increase in coal inventory. The $132$98 million outflow from Accounts Payable was primarily due to APCo’s provisionpayments for revenue refund of $77 million which was paidstorm costs accrued in the firstfourth quarter of 2009 toand decreased purchases of energy from the AEP West companies as part of a FERC order on the SIA.system pool. The $52$81 million inflow from Accounts Receivable, Net was primarily due to a decrease in accrued unbilled revenues due to usual seasonal fluctuations and timing of settlements of receivables from affiliated companies. The $181$41 million outflowinflow from Fuel, Over/Under-Recovery, NetMaterials and Supplies was primarily due to a net under-recoveryreduction in fuel inventory and a decrease in the average cost of fuel costs in both Virginia and West Virginia.coal per ton.
Investing Activities
Net Cash Flows Used for Investing Activities during 2011 and 2010 and 2009 were $363$493 million and $407$168 million, respectively. Construction Expendituresexpenditures of $363$113 million and $420$167 million in 20102011 and 2009,2010, respectively, were primarily for projects to improve service reliability for transmission and distribution, as well as environmental upgrades. Environmental upgrades primarily include the installation of FGD equipment at the Amos Plant. During 2011, APCo increased loans to the Utility Money Pool by $384 million.
Financing Activities
Net Cash Flows Used forfrom Financing Activities were $204$243 million in 2010.2011. APCo issued $300$350 million of Senior Unsecured Notes and $68$295 million of Pollution Control Bonds, partially offset by the retirement of $230 million of Pollution Control Bonds. APCo had a net decrease of $174 million in borrowings from the Utility Money Pool. APCo retired $150 million of Senior Unsecured Notes, $100 million of Notes Payable – Affiliated and $50 million of Pollution Control Bonds. In addition, APCo paid $88 million in dividends on common stock.
Net Cash Flows from Financing Activities were $460 million in 2009. APCo issued $350 million of Senior Unsecured Notes and retired $150 million of Senior Unsecured Notes. APCo received a capital contribution from Parent of $250 million. APCo had a net increase of $37$128 million in borrowings from the Utility Money Pool. In addition, APCo paid $20$38 million in dividends on common stock.stock dividends.
Net Cash Flows Used for Financing Activities were $10 million in 2010. APCo had a net increase of $118 million in borrowings from the Utility Money Pool. APCo retired $100 million of Notes Payable - Affiliated and issued $17.5 million of Pollution Control Bonds in 2010. In addition, APCo paid $44 million in common stock dividends. 88
In April 2011, APCo retired $250 million of 5.55% Senior Unsecured Notes due in 2011.Long-term debt issuances, retirements and principal payments made during the first ninethree months of 20102011 were:
Issuances | | | | | | | | |
| | | Principal | | Interest | | Due |
| Type of Debt | | Amount | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| Pollution Control Bonds | | $ | 17,500 | | 4.625 | | 2021 |
| Pollution Control Bonds | | | 50,000 | | 5.375 | | 2038 |
| Senior Unsecured Notes | | | 300,000 | | 3.40 | | 2015 |
Issuances | | | | | | | | |
| | | Principal | | Interest | | Due |
| Type of Debt | | Amount | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| Senior Unsecured Notes | | $ | 350,000 | | 4.60 | | 2021 |
| Pollution Control Bonds | | | 65,350 | | 2.00 | | 2012 |
| Pollution Control Bonds | | | 75,000 | (a) | Variable | | 2036 |
| Pollution Control Bonds | | | 50,275 | (a) | Variable | | 2036 |
| Pollution Control Bonds | | | 54,375 | (a) | Variable | | 2042 |
| Pollution Control Bonds | | | 50,000 | (a) | Variable | | 2042 |
Retirements and Principal Payments | | | | | | | |
| | | Principal | | Interest | | Due |
| Type of Debt | | Amount Paid | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| Notes Payable – Affiliated | | $ | 100,000 | | 4.708 | | 2010 |
| Senior Unsecured Notes | | | 150,000 | | 4.40 | | 2010 |
| Pollution Control Bonds | | | 50,000 | | 7.125 | | 2010 |
| Land Note | | | 14 | | 13.718 | | 2026 |
| (a) | These pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on APCo’s Condensed Consolidated Balance Sheets. |
SUMMARYRetirements and Principal Payments | | | | | | | |
| | | Principal | | Interest | | Due |
| Type of Debt | | Amount Paid | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| Pollution Control Bonds | | $ | 75,000 | | Variable | | 2036 |
| Pollution Control Bonds | | | 50,275 | | Variable | | 2036 |
| Pollution Control Bonds | | | 54,375 | | Variable | | 2042 |
| Pollution Control Bonds | | | 50,000 | | Variable | | 2042 |
| Land Note | | | 5 | | 13.718 | | 2026 |
CONTRACTUAL OBLIGATION INFORMATION
A summary of contractual obligations is included in the 20092010 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” above.
EXECUTIVE OVERVIEW
REGULATORY ACTIVITY
Virginia Regulatory Activity
In July 2009, APCo filed a generation and distribution base rate increase with the Virginia SCC of $154 million annually based on a 13.35% return on common equity. Interim rates, subject to refund, became effective in December 2009 but were discontinued in February 2010 when newly enacted Virginia legislation suspended the collection of interim rates. In July 2010, the Virginia SCC issued an order approving a $62 million increase based on a 10.53% return on equity. The order denied recovery of the Virginia share of the Mountaineer Carbon Capture and Storage Project, which resulted in a pretax write-off of approximately $54 million in the second quarter of 2010. In addition, the order allowed the deferral of approximately $25 million of incremental storm expense incurred in 2009. See “2009 Virginia Base Rate Case” section of Note 3.above.
In June 2010, the Virginia SCC denied APCo’s request to include certain wind purchased power agreements (Beech Ridge and Grand Ridge) with a 20-year term in its Virginia renewable energy portfolio standard program. As a result, APCo recorded an expense of $4 million in June 2010 to reduce the regulatory asset related to the Virginia portion of wind power costs to write off the difference between the actual Grand Ridge purchased power costs incurred from September 2009 through June 2010 and the estimated cost of non-wind power, which management believes is probable of recovery. Management continues to evaluate several options regarding the Beech Ridge and Grand Ridge contracts. APCo’s future net income and cash flows will be reduced by the unrecoverable Virginia portion of the Beech Ridge a nd Grand Ridge costs until such time as the contracts are reassigned, renegotiated or terminated.
West Virginia Regulatory Activity
In May 2010, APCo filed a request with the WVPSC to increase annual base rates by $140 million based on an 11.75% return on common equity to be effective March 2011. Hearings are scheduled for December 2010. A decision from the WVPSC is expected in March 2011. See “2010 West Virginia Base Rate Case” section of Note 3.
In a proceeding established by the WVPSC to explore options to meet WPCo's future power supply requirements, the WVPSC, in November 2009, issued an order approving a joint stipulation among APCo, WPCo, the WVPSC staff and the Consumer Advocate Division. The order approved the recommendation of the signatories to the stipulation that WPCo merge into APCo and be supplied from APCo's existing power resources. Merger approvals from the WVPSC, Virginia SCC and the FERC are required. No merger approval filings have been made. See “WPCo Merger with APCo” section of Note 3.
Mountaineer Carbon Capture and Storage Project
APCo and ALSTOM Power, Inc. (Alstom), an unrelated third party, jointly constructed a CO2 capture validation facility, which was placed into service in September 2009. APCo also constructed and owns the necessary facilities to store the CO2. In APCo’s July 2009 Virginia base rate filing and May 2010 West Virginia base rate filing, APCo requested recovery of and a return on its Virginia and West Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion. In July 2010, the Virginia SCC issued a base rate order that denied recovery of the Virginia share of the Mo untaineer Carbon Capture and Storage Project costs, which resulted in a write-off of approximately $54 million in the second quarter of 2010. In response to the order, APCo filed with the Virginia SCC a petition for reconsideration of the order as it relates to the Mountaineer Carbon Capture and Storage Project which was denied in August 2010. Through September 30, 2010, APCo has recorded a noncurrent regulatory asset of $59 million related to the Mountaineer Carbon Capture and Storage Project. If APCo cannot recover its remaining investments in and expenses related to the Mountaineer Carbon Capture and Storage project, it would reduce future net income and cash flows and impact financial condition. See “Mountaineer Carbon Capture and Storage Project” section of Note 3.
LITIGATION AND ENVIRONMENTAL ISSUES
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 resolution will be or the timing and amount of any loss, fine or penalty may be. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss 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 2009 Annual Report. Also, see Note 3 – Rate Matters and Note 4 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condense d Financial Statements beginning on page 161. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.
See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 230 for additional discussion of relevant factors.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 20092010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.
See the “New Accounting“Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230201 for a discussion of the adoption and impact of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK MANAGEMENT ACTIVITIES
See “Quantitative And Qualitative Disclosures About Risk Management Activities”Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230201 for a discussion of risk management activities.market risk.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | APPALACHIAN POWER COMPANY AND SUBSIDIARIES | | APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF INCOME | CONDENSED CONSOLIDATED STATEMENTS OF INCOME | | CONDENSED CONSOLIDATED STATEMENTS OF INCOME | |
For the Three and Nine Months Ended September 30, 2010 and 2009 | | |
For the Three Months Ended March 31, 2011 and 2010 | | For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | (in thousands) | | (in thousands) | |
(Unaudited) | (Unaudited) | | (Unaudited) | |
| | |
| | |
| | Three Months Ended | | | Nine Months Ended | | | | | | | |
| | 2010 | | | 2009 | | | 2010 | | | 2009 | | | 2011 | | | 2010 | |
REVENUES | | | | | | | | | | | | | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 754,940 | | | $ | 629,566 | | | $ | 2,234,070 | | | $ | 1,929,552 | | | $ | 751,012 | | | $ | 845,990 | |
Sales to AEP Affiliates | | | 83,675 | | | | 63,645 | | | | 229,811 | | | | 181,914 | | | | 78,691 | | | | 78,771 | |
Other Revenues | | | 2,007 | | | | 2,462 | | | | 6,638 | | | | 6,348 | | | | 2,117 | | | | 1,862 | |
TOTAL REVENUES | | | 840,622 | | | | 695,673 | | | | 2,470,519 | | | | 2,117,814 | | | | 831,820 | | | | 926,623 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
EXPENSES | | | | | | | | | | | | | | | | | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 190,538 | | | | 140,321 | | | | 540,794 | | | | 402,893 | | | | 180,581 | | | | 180,640 | |
Purchased Electricity for Resale | | | 60,751 | | | | 54,087 | | | | 181,370 | | | | 189,534 | | | | 69,218 | | | | 63,683 | |
Purchased Electricity from AEP Affiliates | | | 243,772 | | | | 202,043 | | | | 690,881 | | | | 570,231 | | | | 224,189 | | | | 267,502 | |
Other Operation | | | 77,138 | | | | 68,402 | | | | 338,085 | | | | 197,441 | | | | 113,276 | | | | 90,040 | |
Maintenance | | | 53,276 | | | | 53,164 | | | | 130,446 | | | | 158,552 | | | | 32,293 | | | | 63,110 | |
Depreciation and Amortization | | | 76,737 | | | | 69,701 | | | | 227,327 | | | | 203,844 | | | | 69,099 | | | | 77,430 | |
Taxes Other Than Income Taxes | | | 26,350 | | | | 24,257 | | | | 82,585 | | | | 72,156 | | | | 27,103 | | | | 26,280 | |
TOTAL EXPENSES | | | 728,562 | | | | 611,975 | | | | 2,191,488 | | | | 1,794,651 | | | | 715,759 | | | | 768,685 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 112,060 | | | | 83,698 | | | | 279,031 | | | | 323,163 | | | | 116,061 | | | | 157,938 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | | | | |
Interest Income | | | 210 | | | | 301 | | | | 1,163 | | | | 1,078 | | | | 320 | | | | 291 | |
Carrying Costs Income | | | 7,565 | | | | 6,467 | | | | 23,627 | | | | 16,341 | | | | 3,439 | | | | 5,764 | |
Allowance for Equity Funds Used During Construction | | | 436 | | | | 1,897 | | | | 1,727 | | | | 5,734 | | | | 883 | | | | 1,163 | |
Interest Expense | | | (52,734 | ) | | | (51,982 | ) | | | (156,292 | ) | | | (153,144 | ) | | | (52,939 | ) | | | (51,727 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 67,537 | | | | 40,381 | | | | 149,256 | | | | 193,172 | | | | 67,764 | | | | 113,429 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Income Tax Expense | | | 17,466 | | | | 13,011 | | | | 48,522 | | | | 62,225 | | | | 28,784 | | | | 43,147 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
NET INCOME | | | 50,071 | | | | 27,370 | | | | 100,734 | | | | 130,947 | | | | 38,980 | | | | 70,282 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Preferred Stock Dividend Requirements Including Capital | | | | | | | | | | | | | | | | | |
Stock Expense | | | 225 | | | | 225 | | | | 675 | | | | 675 | | |
Preferred Stock Dividend Requirements Including Capital Stock Expense | | | | 200 | | | | 225 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
EARNINGS ATTRIBUTABLE TO COMMON | | | | | | | | | | | | | | | | | |
STOCK | | $ | 49,846 | | | $ | 27,145 | | | $ | 100,059 | | | $ | 130,272 | | |
EARNINGS ATTRIBUTABLE TO COMMON STOCK | | | $ | 38,780 | | | $ | 70,057 | |
| | | | |
The common stock of APCo is wholly-owned by AEP. | The common stock of APCo is wholly-owned by AEP. | | The common stock of APCo is wholly-owned by AEP. | |
| | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | | See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | APPALACHIAN POWER COMPANY AND SUBSIDIARIES | | APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S | CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S | | CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S | |
EQUITY AND COMPREHENSIVE INCOME (LOSS) | EQUITY AND COMPREHENSIVE INCOME (LOSS) | | EQUITY AND COMPREHENSIVE INCOME (LOSS) | |
For the Nine Months Ended September 30, 2010 and 2009 | | |
For the Three Months Ended March 31, 2011 and 2010 | | For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | (in thousands) | | (in thousands) | |
(Unaudited) | (Unaudited) | | (Unaudited) | |
| | | | |
| | | | | | | | | | | Accumulated | | | | | | | | | | | | | | | Accumulated | | | | |
| | | | | | | | | | | Other | | | | | | | | | | | | | | | Other | | | | |
| | Common | | | Paid-in | | | Retained | | | Comprehensive | | | | | | Common | | | Paid-in | | | Retained | | | Comprehensive | | | | |
| | Stock | | | Capital | | | Earnings | | | Income (Loss) | | | Total | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2008 | | $ | 260,458 | | | $ | 1,225,292 | | | $ | 951,066 | | | $ | (60,225 | ) | | $ | 2,376,591 | | |
| | | | | | | | | | | | | | | | | | | | | |
Capital Contribution from Parent | | | | | | | 250,000 | | | | | | | | | | | | 250,000 | | |
Common Stock Dividends | | | | | | | | | | | (20,000 | ) | | | | | | | (20,000 | ) | |
Preferred Stock Dividends | | | | | | | | | | | (599 | ) | | | | | | | (599 | ) | |
Capital Stock Expense | | | | | | | 76 | | | | (76 | ) | | | | | | | - | | |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 2,605,992 | | |
| | | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of | | | | | | | | | | | | | | | | | | | | | |
Taxes: | | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $545 | | | | | | | | | | | | | | | (1,013 | ) | | | (1,013 | ) | |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $1,982 | | | | | | | | | | | | | | | 3,680 | | | | 3,680 | | |
NET INCOME | | | | | | | | | | | 130,947 | | | | | | | | 130,947 | | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 133,614 | | |
| | | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | |
EQUITY – SEPTEMBER 30, 2009 | | $ | 260,458 | | | $ | 1,475,368 | | | $ | 1,061,338 | | | $ | (57,558 | ) | | $ | 2,739,606 | | |
| | | | | | | | | | | | | | | | | | | | | | Stock | | | Capital | | | Earnings | | | Income (Loss) | | | Total | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2009 | | $ | 260,458 | | | $ | 1,475,393 | | | $ | 1,085,980 | | | $ | (50,254 | ) | | $ | 2,771,577 | | | $ | 260,458 | | | $ | 1,475,393 | | | $ | 1,085,980 | | | $ | (50,254 | ) | | $ | 2,771,577 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (88,000 | ) | | | | | | | (88,000 | ) | | | | | | | | | | | (44,000 | ) | | | | | | | (44,000 | ) |
Preferred Stock Dividends | | | | | | | | | | | (599 | ) | | | | | | | (599 | ) | | | | | | | | | | | (200 | ) | | | | | | | (200 | ) |
Capital Stock Expense | | | | | | | 78 | | | | (76 | ) | | | | | | | 2 | | | | | | | | 27 | | | | (25 | ) | | | | | | | 2 | |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 2,682,980 | | | | | | | | | | | | | | | | | | | | 2,727,379 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Taxes: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $1,953 | | | | | | | | | | | | | | | (3,627 | ) | | | (3,627 | ) | |
Cash Flow Hedges, Net of Tax of $940 | | | | | | | | | | | | | | | | (1,746 | ) | | | (1,746 | ) |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $1,685 | | | | | | | | | | | | | | | 3,129 | | | | 3,129 | | |
Costs, Net of Tax of $562 | | | | | | | | | | | | | | | | 1,043 | | | | 1,043 | |
NET INCOME | | | | | | | | | | | 100,734 | | | | | | | | 100,734 | | | | | | | | | | | | 70,282 | | | | | | | | 70,282 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 100,236 | | | | | | | | | | | | | | | | | | | | 69,579 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
EQUITY – SEPTEMBER 30, 2010 | | $ | 260,458 | | | $ | 1,475,471 | | | $ | 1,098,039 | | | $ | (50,752 | ) | | $ | 2,783,216 | | |
EQUITY – MARCH 31, 2010 | | | $ | 260,458 | | | $ | 1,475,420 | | | $ | 1,112,037 | | | $ | (50,957 | ) | | $ | 2,796,958 | |
| | | | | | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2010 | | | $ | 260,458 | | | $ | 1,475,496 | | | $ | 1,133,748 | | | $ | (48,023 | ) | | $ | 2,821,679 | |
| | | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | | (37,500 | ) | | | | | | | (37,500 | ) |
Preferred Stock Dividends | | | | | | | | | | | | (200 | ) | | | | | | | (200 | ) |
Capital Stock Expense | | | | | | | | 3 | | | | | | | | | | | | 3 | |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | | 2,783,982 | |
| | | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of | | | | | | | | | | | | | | | | | | | | | |
Taxes: | | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $275 | | | | | | | | | | | | | | | | 511 | | | | 511 | |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $418 | | | | | | | | | | | | | | | | 777 | | | | 777 | |
NET INCOME | | | | | | | | | | | | 38,980 | | | | | | | | 38,980 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | 40,268 | |
| | | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | |
EQUITY – MARCH 31, 2011 | | | $ | 260,458 | | | $ | 1,475,499 | | | $ | 1,135,028 | | | $ | (46,735 | ) | | $ | 2,824,250 | |
| | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | | See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
ASSETS | |
September 30, 2010 and December 31, 2009 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2010 | | | 2009 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 2,201 | | | $ | 2,006 | |
Accounts Receivable: | | | | | | | | |
Customers | | | 140,479 | | | | 150,285 | |
Affiliated Companies | | | 66,742 | | | | 135,686 | |
Accrued Unbilled Revenues | | | 57,588 | | | | 68,971 | |
Miscellaneous | | | 4,204 | | | | 6,690 | |
Allowance for Uncollectible Accounts | | | (6,576 | ) | | | (5,408 | ) |
Total Accounts Receivable | | | 262,437 | | | | 356,224 | |
Fuel | | | 210,998 | | | | 343,261 | |
Materials and Supplies | | | 88,082 | | | | 88,575 | |
Risk Management Assets | | | 61,199 | | | | 67,956 | |
Accrued Tax Benefits | | | 52,903 | | | | 180,708 | |
Regulatory Asset for Under-Recovered Fuel Costs | | | 16,224 | | | | 78,685 | |
Prepayments and Other Current Assets | | | 40,266 | | | | 36,293 | |
TOTAL CURRENT ASSETS | | | 734,310 | | | | 1,153,708 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Production | | | 4,657,079 | | | | 4,284,361 | |
Transmission | | | 1,841,919 | | | | 1,813,777 | |
Distribution | | | 2,713,019 | | | | 2,642,479 | |
Other Property, Plant and Equipment | | | 366,450 | | | | 329,497 | |
Construction Work in Progress | | | 491,080 | | | | 730,099 | |
Total Property, Plant and Equipment | | | 10,069,547 | | | | 9,800,213 | |
Accumulated Depreciation and Amortization | | | 2,847,620 | | | | 2,751,443 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 7,221,927 | | | | 7,048,770 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 1,465,997 | | | | 1,433,791 | |
Long-term Risk Management Assets | | | 51,866 | | | | 47,141 | |
Deferred Charges and Other Noncurrent Assets | | | 109,374 | | | | 113,003 | |
TOTAL OTHER NONCURRENT ASSETS | | | 1,627,237 | | | | 1,593,935 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 9,583,474 | | | $ | 9,796,413 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
LIABILITIES AND SHAREHOLDERS' EQUITY | |
September 30, 2010 and December 31, 2009 | |
(Unaudited) | |
| |
| | 2010 | | | 2009 | |
| | (in thousands) | |
CURRENT LIABILITIES | | | | | | |
Advances from Affiliates | | $ | 55,113 | | | $ | 229,546 | |
Accounts Payable: | | | | | | | | |
General | | | 168,749 | | | | 291,240 | |
Affiliated Companies | | | 111,005 | | | | 157,640 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 250,021 | | | | 200,019 | |
Long-term Debt Due Within One Year – Affiliated | | | - | | | | 100,000 | |
Risk Management Liabilities | | | 28,193 | | | | 25,792 | |
Customer Deposits | | | 57,460 | | | | 57,578 | |
Deferred Income Taxes | | | 48,976 | | | | 68,706 | |
Accrued Taxes | | | 45,146 | | | | 65,241 | |
Accrued Interest | | | 71,090 | | | | 58,962 | |
Other Current Liabilities | | | 84,262 | | | | 95,292 | |
TOTAL CURRENT LIABILITIES | | | 920,015 | | | | 1,350,016 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 3,310,938 | | | | 3,177,287 | |
Long-term Risk Management Liabilities | | | 16,329 | | | | 20,364 | |
Deferred Income Taxes | | | 1,529,082 | | | | 1,439,884 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 547,810 | | | | 526,546 | |
Employee Benefits and Pension Obligations | | | 279,060 | | | | 312,873 | |
Deferred Credits and Other Noncurrent Liabilities | | | 179,277 | | | | 180,114 | |
TOTAL NONCURRENT LIABILITIES | | | 5,862,496 | | | | 5,657,068 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 6,782,511 | | | | 7,007,084 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 17,747 | | | | 17,752 | |
| | | | | | | | |
Rate Matters (Note 3) | | | | | | | | |
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 | |
Paid-in Capital | | | 1,475,471 | | | | 1,475,393 | |
Retained Earnings | | | 1,098,039 | | | | 1,085,980 | |
Accumulated Other Comprehensive Income (Loss) | | | (50,752 | ) | | | (50,254 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | | 2,783,216 | | | | 2,771,577 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 9,583,474 | | | $ | 9,796,413 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |
For the Nine Months Ended September 30, 2010 and 2009 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2010 | | | 2009 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 100,734 | | | $ | 130,947 | |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) | | | | | | | | |
Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 227,327 | | | | 203,844 | |
Deferred Income Taxes | | | 52,798 | | | | 229,246 | |
Carrying Costs Income | | | (23,627 | ) | | | (16,341 | ) |
Allowance for Equity Funds Used During Construction | | | (1,727 | ) | | | (5,734 | ) |
Mark-to-Market of Risk Management Contracts | | | (2,573 | ) | | | (31,415 | ) |
Pension Contributions to Qualified Plan Trust | | | (31,952 | ) | | | - | |
Property Taxes | | | 19,660 | | | | 18,617 | |
Fuel Over/Under-Recovery, Net | | | (17,136 | ) | | | (181,241 | ) |
Change in Other Noncurrent Assets | | | 29,275 | | | | (57,087 | ) |
Change in Other Noncurrent Liabilities | | | 4,558 | | | | 22,595 | |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 93,787 | | | | 51,667 | |
Fuel, Materials and Supplies | | | 132,801 | | | | (159,904 | ) |
Accounts Payable | | | (113,912 | ) | | | (131,914 | ) |
Accrued Taxes, Net | | | 107,404 | | | | (95,962 | ) |
Other Current Assets | | | (4,416 | ) | | | (14,172 | ) |
Other Current Liabilities | | | (5,537 | ) | | | (16,858 | ) |
Net Cash Flows from (Used for) Operating Activities | | | 567,464 | | | | (53,712 | ) |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (362,792 | ) | | | (420,075 | ) |
Change in Other Cash Deposits | | | 1,970 | | | | 235 | |
Acquisitions of Assets | | | (9,595 | ) | | | (1,024 | ) |
Proceeds from Sales of Assets | | | 7,171 | | | | 14,157 | |
Net Cash Flows Used for Investing Activities | | | (363,246 | ) | | | (406,707 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Capital Contribution from Parent | | | - | | | | 250,000 | |
Issuance of Long-term Debt – Nonaffiliated | | | 363,736 | | | | 345,658 | |
Change in Advances from Affiliates, Net | | | (174,433 | ) | | | 36,900 | |
Retirement of Long-term Debt – Nonaffiliated | | | (200,014 | ) | | | (150,012 | ) |
Retirement of Long-term Debt – Affiliated | | | (100,000 | ) | | | - | |
Retirement of Cumulative Preferred Stock | | | (4 | ) | | | - | |
Principal Payments for Capital Lease Obligations | | | (5,350 | ) | | | (2,582 | ) |
Dividends Paid on Common Stock | | | (88,000 | ) | | | (20,000 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (599 | ) | | | (599 | ) |
Other Financing Activities | | | 641 | | | | 872 | |
Net Cash Flows from (Used for) Financing Activities | | | (204,023 | ) | | | 460,237 | |
| | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 195 | | | | (182 | ) |
Cash and Cash Equivalents at Beginning of Period | | | 2,006 | | | | 1,996 | |
Cash and Cash Equivalents at End of Period | | $ | 2,201 | | | $ | 1,814 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 140,391 | | | $ | 148,745 | |
Net Cash Paid (Received) for Income Taxes | | | (140,113 | ) | | | (14,679 | ) |
Noncash Acquisitions Under Capital Leases | | | 22,623 | | | | 884 | |
Construction Expenditures Included in Accounts Payable at September 30, | | | 52,863 | | | | 56,989 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
ASSETS | |
March 31, 2011 and December 31, 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 2,384 | | | $ | 951 | |
Advances to Affiliates | | | 383,537 | | | | - | |
Accounts Receivable: | | | | | | | | |
Customers | | | 153,002 | | | | 166,878 | |
Affiliated Companies | | | 101,346 | | | | 145,972 | |
Accrued Unbilled Revenues | | | 58,693 | | | | 108,210 | |
Miscellaneous | | | 1,348 | | | | 3,090 | |
Allowance for Uncollectible Accounts | | | (7,045 | ) | | | (6,667 | ) |
Total Accounts Receivable | | | 307,344 | | | | 417,483 | |
Fuel | | | 167,153 | | | | 230,697 | |
Materials and Supplies | | | 91,068 | | | | 89,370 | |
Risk Management Assets | | | 38,923 | | | | 53,242 | |
Accrued Tax Benefits | | | 109,294 | | | | 104,435 | |
Regulatory Asset for Under-Recovered Fuel Costs | | | 18,131 | | | | 18,300 | |
Prepayments and Other Current Assets | | | 29,707 | | | | 35,811 | |
TOTAL CURRENT ASSETS | | | 1,147,541 | | | | 950,289 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Generation | | | 5,096,419 | | | | 4,736,150 | |
Transmission | | | 1,874,320 | | | | 1,852,415 | |
Distribution | | | 2,760,683 | | | | 2,740,752 | |
Other Property, Plant and Equipment | | | 348,613 | | | | 348,013 | |
Construction Work in Progress | | | 209,978 | | | | 562,280 | |
Total Property, Plant and Equipment | | | 10,290,013 | | | | 10,239,610 | |
Accumulated Depreciation and Amortization | | | 2,882,681 | | | | 2,843,087 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 7,407,332 | | | | 7,396,523 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 1,485,103 | | | | 1,486,625 | |
Long-term Risk Management Assets | | | 40,266 | | | | 38,420 | |
Deferred Charges and Other Noncurrent Assets | | | 128,641 | | | | 125,296 | |
TOTAL OTHER NONCURRENT ASSETS | | | 1,654,010 | | | | 1,650,341 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 10,208,883 | | | $ | 9,997,153 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
LIABILITIES AND SHAREHOLDERS' EQUITY | |
March 31, 2011 and December 31, 2010 | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
| | (in thousands) | |
CURRENT LIABILITIES | | | | | | |
Advances from Affiliates | | $ | - | | | $ | 128,331 | |
Accounts Payable: | | | | | | | | |
General | | | 155,890 | | | | 223,144 | |
Affiliated Companies | | | 133,716 | | | | 166,884 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 479,673 | | | | 479,672 | |
Risk Management Liabilities | | | 22,746 | | | | 27,993 | |
Customer Deposits | | | 59,385 | | | | 58,451 | |
Deferred Income Taxes | | | 40,752 | | | | 44,180 | |
Accrued Taxes | | | 76,268 | | | | 75,619 | |
Accrued Interest | | | 71,566 | | | | 57,871 | |
Other Current Liabilities | | | 81,662 | | | | 93,286 | |
TOTAL CURRENT LIABILITIES | | | 1,121,658 | | | | 1,355,431 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 3,496,032 | | | | 3,081,469 | |
Long-term Risk Management Liabilities | | | 13,339 | | | | 10,873 | |
Deferred Income Taxes | | | 1,679,963 | | | | 1,642,072 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 554,577 | | | | 562,381 | |
Employee Benefits and Pension Obligations | | | 302,517 | | | | 306,460 | |
Deferred Credits and Other Noncurrent Liabilities | | | 198,811 | | | | 199,041 | |
TOTAL NONCURRENT LIABILITIES | | | 6,245,239 | | | | 5,802,296 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 7,366,897 | | | | 7,157,727 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 17,736 | | | | 17,747 | |
| | | | | | | | |
Rate Matters (Note 2) | | | | | | | | |
Commitments and Contingencies (Note 3) | | | | | | | | |
| | | | | | | | |
COMMON SHAREHOLDER’S EQUITY | | | | | | | | |
Common Stock – No Par Value: | | | | | | | | |
Authorized – 30,000,000 Shares | | | | | | | | |
Outstanding – 13,499,500 Shares | | | 260,458 | | | | 260,458 | |
Paid-in Capital | | | 1,475,499 | | | | 1,475,496 | |
Retained Earnings | | | 1,135,028 | | | | 1,133,748 | |
Accumulated Other Comprehensive Income (Loss) | | | (46,735 | ) | | | (48,023 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | | 2,824,250 | | | | 2,821,679 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 10,208,883 | | | $ | 9,997,153 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 38,980 | | | $ | 70,282 | |
Adjustments to Reconcile Net Income to Net Cash Flows from | | | | | | | | |
Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 69,099 | | | | 77,430 | |
Deferred Income Taxes | | | 60,802 | | | | 19,121 | |
Carrying Costs Income | | | (3,439 | ) | | | (5,764 | ) |
Allowance for Equity Funds Used During Construction | | | (883 | ) | | | (1,163 | ) |
Mark-to-Market of Risk Management Contracts | | | (1,553 | ) | | | (12,977 | ) |
Fuel Over/Under-Recovery, Net | | | (9,857 | ) | | | (11,804 | ) |
Change in Other Noncurrent Assets | | | 10,237 | | | | 11,082 | |
Change in Other Noncurrent Liabilities | | | 12,013 | | | | (2,568 | ) |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 109,662 | | | | 80,813 | |
Fuel, Materials and Supplies | | | 61,846 | | | | 41,054 | |
Accounts Payable | | | (71,056 | ) | | | (97,732 | ) |
Accrued Taxes, Net | | | (32,472 | ) | | | 24,150 | |
Other Current Assets | | | 6,505 | | | | (4,250 | ) |
Other Current Liabilities | | | 957 | | | | (9,152 | ) |
Net Cash Flows from Operating Activities | | | 250,841 | | | | 178,522 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (113,132 | ) | | | (167,412 | ) |
Change in Advances to Affiliates, Net | | | (383,537 | ) | | | - | |
Other Investing Activities | | | 4,047 | | | | (566 | ) |
Net Cash Flows Used for Investing Activities | | | (492,622 | ) | | | (167,978 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Long-term Debt – Nonaffiliated | | | 640,770 | | | | 17,376 | |
Change in Advances from Affiliates, Net | | | (128,331 | ) | | | 117,879 | |
Retirement of Long-term Debt – Nonaffiliated | | | (229,655 | ) | | | (5 | ) |
Retirement of Long-term Debt – Affiliated | | | - | | | | (100,000 | ) |
Retirement of Cumulative Preferred Stock | | | (8 | ) | | | (4 | ) |
Principal Payments for Capital Lease Obligations | | | (1,876 | ) | | | (1,790 | ) |
Dividends Paid on Common Stock | | | (37,500 | ) | | | (44,000 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (200 | ) | | | (200 | ) |
Other Financing Activities | | | 14 | | | | 436 | |
Net Cash Flows from (Used for) Financing Activities | | | 243,214 | | | | (10,308 | ) |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 1,433 | | | | 236 | |
Cash and Cash Equivalents at Beginning of Period | | | 951 | | | | 2,006 | |
Cash and Cash Equivalents at End of Period | | $ | 2,384 | | | $ | 2,242 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 36,992 | | | $ | 38,971 | |
Net Cash Paid for Income Taxes | | | 629 | | | | - | |
Noncash Acquisitions Under Capital Leases | | | 368 | | | | 20,369 | |
Government Grants Included in Accounts Receivable at March 31, | | | 572 | | | | - | |
Construction Expenditures Included in Current Liabilities at March 31, | | | 38,071 | | | | 43,262 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
INDEX TOOF 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. The footnotes begin on page 161.143.
| Footnote Reference |
| |
Significant Accounting Matters | Note 1 |
New Accounting Pronouncements and Extraordinary Item | Note 2 |
Rate Matters | Note 32 |
| |
Commitments, Guarantees and Contingencies | Note 43 |
| |
Benefit Plans | Note 65 |
| |
Business Segments | Note 76 |
| |
Derivatives and Hedging | Note 87 |
| |
Fair Value Measurements | Note 98 |
| |
Income Taxes | Note 109 |
| |
Financing Activities | Note 1110 |
| |
Cost Reduction Initiatives | Note 1211 |
COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS | |
| | | |
RESULTS OF OPERATIONS | | | |
| | | |
Third Quarter of 2010 Compared to Third Quarter of 2009 | |
| | | |
Reconciliation of Third Quarter of 2009 to Third Quarter of 2010 | |
Net Income | |
(in millions) | |
| | | |
Third Quarter of 2009 | | $ | 98 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins | | | 30 | |
Off-system Sales | | | 14 | |
Other Revenues | | | 1 | |
Total Change in Gross Margin | | | 45 | |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | (17 | ) |
Depreciation and Amortization | | | (2 | ) |
Taxes Other Than Income Taxes | | | (7 | ) |
Interest Expense | | | 1 | |
Total Expenses and Other | | | (25 | ) |
| | | | |
Income Tax Expense | | | (11 | ) |
| | | | |
Third Quarter of 2010 | | $ | 107 | |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
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 $30 million due to:
|
| · | A $32 million increase in residential and commercial revenue from weather-related usage primarily due to a 66% increase in cooling degree days. |
| · | A $13 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Ohio Energy Efficiency & Demand Response Program Rider. This increase in retail margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below. |
| These increases were partially offset by: |
| · | A $5 million decrease in capacity settlements under the Interconnection Agreement. |
| · | A $4 million decrease as a result of the expiration of the City of Westerville contract as a dedicated customer for CSPCo at the end of 2009. A new contract was entered into with Westerville on January 1, 2010 which is included as an Off-system Sale and margins are shared by the members of the AEP Power Pool. |
· | Margins from Off-system Sales increased $14 million primarily due to increased prices and higher physical sales volumes, partially offset by lower trading and marketing margins.
|
Total Expenses and Other and Income Tax Expense changed between years as follows:
· | Other Operation and Maintenance expenses increased $17 million primarily due to:
|
| · | A $13 million increase in expenses due to the implementation of PUCO approved Ohio Energy Efficiency & Demand Response Program. This increase in operation and maintenance expense was offset by a corresponding increase in Retail Margins as discussed above. |
| · | A $3 million increase in recoverable customer account expenses due to increased Universal Service Fund surcharge rates for customers who qualify for payment assistance. |
· | Depreciation and Amortization increased $2 million primarily due to projects at the Conesville Plant that were completed and placed in service in November 2009.
|
· | Taxes Other Than Income Taxes increased $7 million primarily due to a $5 million increase in property taxes.
|
· | Income Tax Expense increased $11 million primarily due to an increase in pretax book income and other book/tax differences which are accounted for a flow-through basis.
|
Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009 |
| | | | |
Reconciliation of Nine Months Ended September 30, 2009 to Nine Months Ended September 30, 2010 |
Net Income |
(in millions) |
| | | | |
Nine Months Ended September 30, 2009 | | $ | 231 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins | | | 18 | |
Off-system Sales | | | 15 | |
Total Change in Gross Margin | | | 33 | |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | (42) | |
Depreciation and Amortization | | | (8) | |
Taxes Other Than Income Taxes | | | (10) | |
Total Expenses and Other | | | (60) | |
| | | | |
Income Tax Expense | | | 7 | |
| | | | |
Nine Months Ended September 30, 2010 | | $ | 211 | |
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 was as follows:
· | Retail Margins increased $18 million due to:
|
| · | A $41 million increase in residential and commercial revenue from weather-related usage primarily due to a 53% increase in cooling degree days. |
| · | A $16 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Ohio Energy Efficiency & Demand Response Program Rider. This increase in retail margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below. |
| These increases were partially offset by: |
| · | A $16 million decrease in capacity settlements under the Interconnection Agreement. |
| · | A $14 million decrease as a result of the elimination of Restructuring Transition Charge (RTC) revenues with the implementation of CSPCo’s ESP. |
| · | A $12 million decrease as a result of the expiration of the City of Westerville contract as a dedicated customer for CSPCo at the end of 2009. A new contract was entered into with Westerville on January 1, 2010 which is included as an Off-system Sale and margins are shared by the members of the AEP Power Pool. |
· | Margins from Off-system Sales increased $15 million primarily due to increased prices and higher physical sales volumes, partially offset by lower trading and marketing margins.
|
Total Expenses and Other and Income Tax Expense changed between years as follows:
· | Other Operation and Maintenance expenses increased $42 million primarily due to:
|
| · | A $31 million increase due to expenses incurred related to the cost reduction initiatives. | |
| · | A $16 million increase in expenses due to the implementation of PUCO approved Ohio Energy Efficiency & Demand Response Program. This increase in operation and maintenance expense was offset by a corresponding increase in Retail Margins as discussed above. | |
| · | A $10 million increase in recoverable customer account expenses due to increased Universal Service Fund surcharge rates for customers who qualify for payment assistance. | |
| These increases were partially offset by: | |
| · | A $7 million decrease related to a 2009 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. | |
| · | A $6 million decrease in boiler plant maintenance expenses primarily related to work performed at the Conesville and Zimmer plants. | |
· | Depreciation and Amortization increased $8 million primarily due to projects at the Conesville Plant that were completed and placed in service in November 2009.
|
· | Taxes Other Than Income Taxes increased $10 million primarily due to an $8 million increase in property taxes.
|
· | Income Tax Expense decreased $7 million primarily due to a decrease in pretax book income partially offset by other book/tax differences which are accounted for on a flow-through basis.
|
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS
EXECUTIVE OVERVIEW
Ohio Customer Choice
In CSPCo’s service territory, various certifiedcompetitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service. As of September 30, 2010,Through March 31, 2011, approximately 2,0007,500 CSPCo retail customers have switched from CSPCo to alternative CRES providers while approximately 1,200 additional customers have provided notice of their intent to switch.providers. As a result, in comparison to 2009,the first three months of 2010, CSPCo lost approximately $5$18 million of generation related gross margin through September 30, 2010. Management currently forecasts incremental lost margins of approximately $10 million and $53 million for the fourth quarter of 2010 and for all of 2011, respectively.March 31, 2011. Management anticipates recovery of a portion of this lost margin through off-system sales.sales, including PJM capacity revenues.
REGULATORY ACTIVITYRegulatory Activity
Ohio Electric Security Plan Filing2009 – 2011 ESPs
During 2009, the PUCO issued an order that modified and approved CSPCo’s ESP which established rates through 2011. The order also limits annual rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011. The order provides a FAC for the three-year period of the ESP. Several notices of appeal are outstanding atIn April 2011, the Supreme Court of Ohio relating to significant issues inissued an opinion addressing the determinationaspects of the approved ESP rates. CSPCo filed its significantly excessive earnings test withPUCO's 2009 decision that were challenged which resulted in three reversals, only two of which may have a prospective impact. If any rate changes result from the PUCO in September 2010. Based uponPUCO’s remand proceedings, such rate changes would be prospective from the methodology proposed by CSPCo indate of the SEET filing, CSPCo’s 2009 return on equity was not significantly excessive. In October 2010, intervenors filed testimony withremand order through the PUCO recommending CSPCo return up to $156 millionremaining months of its ESP revenues to c ustomers. If the PUCO determines that CSPCo’s 2009 return on equity was significantly excessive, CSPCo may be required to return a portion of its ESP revenues to customers.2011. See “Ohio Electric Security Plan Filings” section of Note 3.2.
January 2012 – May 2014 ESP
In January 2011, CSPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing for generation. The rates would be effective with the first billing cycle of January 2012 through the last billing cycle of May 2014. The SSO presents redesigned generation rates by customer class. Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013. Under the new ESP, management estimates CSPCo will have base generation increases, excluding riders, of $17 million for 2012 and $46 million for 2013. The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESP could impact the outcome of the January 2012 – May 2014 ESP, though the nature and extent of that impact is not presently known. See “Ohio Electric Security Plan Filings” section of Note 2.
Ohio Distribution Base Rate Case
In February 2011, CSPCo filed with the PUCO for an annual increase in distribution rates of $34 million. The requested increase is based upon an 11.15% return on common equity to be effective January 2012. In addition to the annual increase, CSPCo requested recovery of the projected December 31, 2012 balance of certain distribution regulatory assets of $216 million, including approximately $102 million of unrecognized equity carrying costs. These assets would be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013. The actual balance of these distribution regulatory assets as of March 31, 2011 was $98 million, excluding $57 million of unrecognized equity carrying costs. If CSPCo is not ultimately permitted to fully recover its deferrals, it would reduce future net income and cash flows and impact financial condition. See “Ohio Distribution Base Rate Case” section of Note 2.
Proposed CSPCo and OPCo Merger
In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo. Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company. The merger is also subject to regulatory approval by the FERC.In January 2011, CSPCo and OPCo anticipate completion offiled an application with the merger duringFERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo. CSPCo and OPCo requested the reorganization transaction be effective in October 2011. Decisions are pending from the PUCO and the FERC. See “Proposed CSPCo and OPCo Merger” section of Note 3.2.
LITIGATION AND ENVIRONMENTAL ISSUESLitigation and Environmental Issues
In the ordinary course of business, CSPCo 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 resolution will be or the timing and amount of any loss, fine or penalty may be. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss 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 20092010 Annual Report. Also, see Note 32 – Rate Matters and Note 43 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condens edCondensed Financial Statements beginning on page 161.143. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.
See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 230201 for additional discussion of relevant factors.
RESULTS OF OPERATIONS | | | | | |
| | | | | | |
KWH Sales/Degree Days | | | | | |
| | | | | | |
Summary of KWH Energy Sales |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in millions of KWH) |
Retail: | | | | | |
| Residential | | 2,127 | | | 2,226 |
| Commercial | | 1,995 | | | 2,002 |
| Industrial | | 1,270 | | | 1,111 |
| Miscellaneous | | 14 | | | 13 |
Total Retail | | 5,406 | | | 5,352 |
| | | | | |
Wholesale | | 863 | | | 719 |
| | | | | |
Total KWHs | | 6,269 | | | 6,071 |
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.
Summary of Heating and Cooling Degree Days |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in degree days) |
| | | | | | |
Actual - Heating (a) | | 1,928 | | | 1,965 |
Normal - Heating (b) | | 1,784 | | | 1,784 |
| | | | | | |
Actual - Cooling (c) | | 1 | | | - |
Normal - Cooling (b) | | 3 | | | 3 |
| | | | | | |
(a) | Eastern 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 cooling degree days are calculated on a 65 degree temperature base. |
First Quarter of 2011 Compared to First Quarter of 2010 | |
| | | |
Reconciliation of First Quarter of 2010 to First Quarter of 2011 | |
Net Income | |
(in millions) | |
| | | |
First Quarter of 2010 | | $ | 52 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins | | | 10 | |
Off-system Sales | | | 12 | |
Total Change in Gross Margin | | | 22 | |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | 1 | |
Depreciation and Amortization | | | (4 | ) |
Taxes Other Than Income Taxes | | | (3 | ) |
Interest Expense | | | 2 | |
Other Income | | | 1 | |
Total Expenses and Other | | | (3 | ) |
| | | | |
Income Tax Expense | | | (6 | ) |
| | | | |
First Quarter of 2011 | | $ | 65 | |
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 $10 million due to the following: |
| · | A $12 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Energy Efficiency & Peak Demand Reduction (EE/PDR) Programs. This increase in Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below. |
| · | A $10 million increase associated with the final 2009 SEET order. |
| · | A $4 million increase in revenues due to the implementation of PUCO approved rider rates in September 2010 related to the Environmental Investment Carrying Cost Rider. |
| These increases were partially offset by: |
| · | An $18 million decrease attributable to customers switching to alternative competitive retail electric service (CRES) providers. |
· | Margins from Off-system Sales increased $12 million primarily due to an increase in PJM capacity revenues, partially offset by lower trading and marketing margins. |
Total Expenses and Other and Income Tax Expense changed between years as follows:
· | Other Operation and Maintenance expenses decreased $1 million primarily due to: |
| · | A $7 million decrease in transmission expense primarily due to the Transmission Agreement modification effective November 2010, a portion of which is included in the Ohio Transmission Cost Recovery Rider. |
| · | A $3 million decrease in employee-related expenses. |
| These decreases were partially offset by: |
| · | A $12 million increase in expenses due to the implementation of PUCO approved EE/PDR programs. This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above. |
· | Depreciation and Amortization expenses increased $4 million as a result of recognizing the deferred debt and equity carrying charges on deferred fuel as permitted under the final 2009 SEET order. |
· | Taxes Other Than Income Taxes increased $3 million due to an increase in property taxes. |
· | Income Tax Expense increased $6 million primarily due to an increase in pre-tax book income, offset in part by the 2010 tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits. |
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 20092010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.
See the “New Accounting“Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230201 for a discussion of the adoption and impact of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK MANAGEMENT ACTIVITIES
See “Quantitative And Qualitative Disclosures About Risk Management Activities”Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230201 for a discussion of risk management activities.market risk.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | | COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF INCOME | CONDENSED CONSOLIDATED STATEMENTS OF INCOME | | CONDENSED CONSOLIDATED STATEMENTS OF INCOME | |
For the Three and Nine Months Ended September 30, 2010 and 2009 | | |
For the Three Months Ended March 31, 2011 and 2010 | | For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | (in thousands) | | (in thousands) | |
(Unaudited) | (Unaudited) | | (Unaudited) | |
| | |
| | Three Months Ended | | | Nine Months Ended | | | | | | | |
| | 2010 | | | 2009 | | | 2010 | | | 2009 | | | 2011 | | | 2010 | |
REVENUES | | | | | | | | | | | | | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 616,823 | | | $ | 533,306 | | | $ | 1,621,112 | | | $ | 1,482,421 | | | $ | 503,371 | | | $ | 501,019 | |
Sales to AEP Affiliates | | | 30,765 | | | | 22,143 | | | | 66,687 | | | | 51,514 | | | | 40,725 | | | | 15,832 | |
Other Revenues | | | 806 | | | | 694 | | | | 2,138 | | | | 1,820 | | | | 506 | | | | 588 | |
TOTAL REVENUES | | | 648,394 | | | | 556,143 | | | | 1,689,937 | | | | 1,535,755 | | | | 544,602 | | | | 517,439 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
EXPENSES | | | | | | | | | | | | | | | | | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 99,883 | | | | 88,523 | | | | 319,614 | | | | 222,943 | | | | 112,913 | | | | 114,441 | |
Purchased Electricity for Resale | | | 28,116 | | | | 21,750 | | | | 67,899 | | | | 74,010 | | | | 23,517 | | | | 19,645 | |
Purchased Electricity from AEP Affiliates | | | 134,467 | | | | 105,120 | | | | 324,553 | | | | 294,280 | | | | 101,611 | | | | 98,799 | |
Other Operation | | | 86,360 | | | | 68,971 | | | | 266,915 | | | | 210,614 | | | | 71,067 | | | | 77,326 | |
Maintenance | | | 23,196 | | | | 23,926 | | | | 72,593 | | | | 86,558 | | | | 29,100 | | | | 24,283 | |
Depreciation and Amortization | | | 38,644 | | | | 36,292 | | | | 113,733 | | | | 105,863 | | | | 41,426 | | | | 37,487 | |
Taxes Other Than Income Taxes | | | 50,884 | | | | 44,149 | | | | 142,235 | | | | 132,576 | | | | 50,149 | | | | 47,057 | |
TOTAL EXPENSES | | | 461,550 | | | | 388,731 | | | | 1,307,542 | | | | 1,126,844 | | | | 429,783 | | | | 419,038 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 186,844 | | | | 167,412 | | | | 382,395 | | | | 408,911 | | | | 114,819 | | | | 98,401 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | | | | |
Interest Income | | | 385 | | | | 144 | | | | 694 | | | | 618 | | | | 167 | | | | 142 | |
Carrying Costs Income | | | 2,028 | | | | 1,984 | | | | 6,212 | | | | 5,394 | | | | 3,654 | | | | 2,221 | |
Allowance for Equity Funds Used During Construction | | | 267 | | | | 914 | | | | 1,502 | | | | 2,799 | | | | 771 | | | | 921 | |
Interest Expense | | | (21,382 | ) | | | (22,487 | ) | | | (64,257 | ) | | | (64,356 | ) | | | (19,748 | ) | | | (21,784 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 168,142 | | | | 147,967 | | | | 326,546 | | | | 353,366 | | | | 99,663 | | | | 79,901 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Income Tax Expense | | | 61,085 | | | | 50,374 | | | | 115,723 | | | | 122,737 | | | | 34,105 | | | | 28,251 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
NET INCOME | | | 107,057 | | | | 97,593 | | | | 210,823 | | | | 230,629 | | | | 65,558 | | | | 51,650 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Capital Stock Expense | | | 39 | | | | 39 | | | | 118 | | | | 118 | | | | 25 | | | | 39 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
EARNINGS ATTRIBUTABLE TO COMMON STOCK | | $ | 107,018 | | | $ | 97,554 | | | $ | 210,705 | | | $ | 230,511 | | | $ | 65,533 | | | $ | 51,611 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
The common stock of CSPCo is wholly-owned by AEP. | | | | | | | | | | | | | | | | | The common stock of CSPCo is wholly-owned by AEP. | |
| | | | | | | | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | | See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | | COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S | CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S | | CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S | |
EQUITY AND COMPREHENSIVE INCOME (LOSS) | EQUITY AND COMPREHENSIVE INCOME (LOSS) | | EQUITY AND COMPREHENSIVE INCOME (LOSS) | |
For the Nine Months Ended September 30, 2010 and 2009 | | |
For the Three Months Ended March 31, 2011 and 2010 | | For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | (in thousands) | | (in thousands) | |
(Unaudited) | (Unaudited) | | (Unaudited) | |
| | | | |
| | | | | | | | | | | Accumulated | | | | | | | | | | | | | | | Accumulated | | | | |
| | | | | | | | | | | Other | | | | | | | | | | | | | | | Other | | | | |
| | Common | | | Paid-in | | | Retained | | | Comprehensive | | | | | | Common | | | Paid-in | | | Retained | | | Comprehensive | | | | |
| | Stock | | | Capital | | | Earnings | | | Income (Loss) | | | Total | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2008 | | $ | 41,026 | | | $ | 580,506 | | | $ | 674,758 | | | $ | (51,025 | ) | | $ | 1,245,265 | | |
| | | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (150,000 | ) | | | | | | | (150,000 | ) | |
Capital Stock Expense | | | | | | | 118 | | | | (118 | ) | | | | | | | - | | |
Noncash Dividend of Property to Parent | | | | | | | | | | | (8,123 | ) | | | | | | | (8,123 | ) | |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 1,087,142 | | |
| | | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of | | | | | | | | | | | | | | | | | | | | | |
Taxes: | | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $699 | | | | | | | | | | | | | | | (1,299 | ) | | | (1,299 | ) | |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $894 | | | | | | | | | | | | | | | 1,661 | | | | 1,661 | | |
NET INCOME | | | | | | | | | | | 230,629 | | | | | | | | 230,629 | | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 230,991 | | |
| | | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | |
EQUITY – SEPTEMBER 30, 2009 | | $ | 41,026 | | | $ | 580,624 | | | $ | 747,146 | | | $ | (50,663 | ) | | $ | 1,318,133 | | |
| | | | | | | | | | | | | | | | | | | | | | Stock | | | Capital | | | Earnings | | | Income (Loss) | | | Total | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2009 | | $ | 41,026 | | | $ | 580,663 | | | $ | 788,139 | | | $ | (49,993 | ) | | $ | 1,359,835 | | | $ | 41,026 | | | $ | 580,663 | | | $ | 788,139 | | | $ | (49,993 | ) | | $ | 1,359,835 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (77,500 | ) | | | | | | | (77,500 | ) | | | | | | | | | | | (31,250 | ) | | | | | | | (31,250 | ) |
Capital Stock Expense | | | | | | | 118 | | | | (118 | ) | | | | | | | - | | | | | | | | 39 | | | | (39 | ) | | | | | | | - | |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 1,282,335 | | | | | | | | | | | | | | | | | | | | 1,328,585 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Taxes: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $462 | | | | | | | | | | | | | | | (857 | ) | | | (857 | ) | |
Cash Flow Hedges, Net of Tax of $555 | | | | | | | | | | | | | | | | (1,031 | ) | | | (1,031 | ) |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $1,000 | | | | | | | | | | | | | | | 1,857 | | | | 1,857 | | |
Costs, Net of Tax of $333 | | | | | | | | | | | | | | | | 619 | | | | 619 | |
NET INCOME | | | | | | | | | | | 210,823 | | | | | | | | 210,823 | | | | | | | | | | | | 51,650 | | | | | | | | 51,650 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 211,823 | | | | | | | | | | | | | | | | | | | | 51,238 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
EQUITY – SEPTEMBER 30, 2010 | | $ | 41,026 | | | $ | 580,781 | | | $ | 921,344 | | | $ | (48,993 | ) | | $ | 1,494,158 | | |
EQUITY – MARCH 31, 2010 | | | $ | 41,026 | | | $ | 580,702 | | | $ | 808,500 | | | $ | (50,405 | ) | | $ | 1,379,823 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2010 | | | $ | 41,026 | | | $ | 580,812 | | | $ | 915,713 | | | $ | (51,336 | ) | | $ | 1,486,215 | |
| | | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | | (62,500 | ) | | | | | | | (62,500 | ) |
Capital Stock Expense | | | | | | | | 25 | | | | (25 | ) | | | | | | | - | |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | | 1,423,715 | |
| | | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $114 | | | | | | | | | | | | | | | | 213 | | | | 213 | |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $344 | | | | | | | | | | | | | | | | 639 | | | | 639 | |
NET INCOME | | | | | | | | | | | | 65,558 | | | | | | | | 65,558 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | 66,410 | |
| | | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | |
EQUITY – MARCH 31, 2011 | | | $ | 41,026 | | | $ | 580,837 | | | $ | 918,746 | | | $ | (50,484 | ) | | $ | 1,490,125 | |
| | | | | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | | See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
ASSETS | |
September 30, 2010 and December 31, 2009 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2010 | | | 2009 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 1,679 | | | $ | 1,096 | |
Other Cash Deposits | | | 2,260 | | | | 16,150 | |
Advances to Affiliates | | | 182,225 | | | | - | |
Accounts Receivable: | | | | | | | | |
Customers | | | 29,835 | | | | 37,158 | |
Affiliated Companies | | | 23,231 | | | | 28,555 | |
Accrued Unbilled Revenues | | | 12,139 | | | | 11,845 | |
Miscellaneous | | | 3,856 | | | | 4,164 | |
Allowance for Uncollectible Accounts | | | (1,984 | ) | | | (3,481 | ) |
Total Accounts Receivable | | | 67,077 | | | | 78,241 | |
Fuel | | | 65,636 | | | | 74,158 | |
Materials and Supplies | | | 42,051 | | | | 39,652 | |
Emission Allowances | | | 22,518 | | | | 26,587 | |
Risk Management Assets | | | 35,166 | | | | 34,343 | |
Accrued Tax Benefits | | | 645 | | | | 29,273 | |
Margin Deposits | | | 14,823 | | | | 14,874 | |
Prepayments and Other Current Assets | | | 25,676 | | | | 6,349 | |
TOTAL CURRENT ASSETS | | | 459,756 | | | | 320,723 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Production | | | 2,650,674 | | | | 2,641,860 | |
Transmission | | | 656,293 | | | | 623,680 | |
Distribution | | | 1,770,707 | | | | 1,745,559 | |
Other Property, Plant and Equipment | | | 205,726 | | | | 189,315 | |
Construction Work in Progress | | | 176,437 | | | | 155,081 | |
Total Property, Plant and Equipment | | | 5,459,837 | | | | 5,355,495 | |
Accumulated Depreciation and Amortization | | | 1,915,830 | | | | 1,838,840 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 3,544,007 | | | | 3,516,655 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 306,113 | | | | 341,029 | |
Long-term Risk Management Assets | | | 29,882 | | | | 23,882 | |
Deferred Charges and Other Noncurrent Assets | | | 74,472 | | | | 147,217 | |
TOTAL OTHER NONCURRENT ASSETS | | | 410,467 | | | | 512,128 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 4,414,230 | | | $ | 4,349,506 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
ASSETS | |
March 31, 2011 and December 31, 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 1,385 | | | $ | 509 | |
Other Cash Deposits | | | 2,260 | | | | 2,260 | |
Advances to Affiliates | | | 63,706 | | | | 54,202 | |
Accounts Receivable: | | | | | | | | |
Customers | | | 50,017 | | | | 50,187 | |
Affiliated Companies | | | 44,261 | | | | 66,788 | |
Accrued Unbilled Revenues | | | 14,205 | | | | 32,821 | |
Miscellaneous | | | 4,715 | | | | 14,374 | |
Allowance for Uncollectible Accounts | | | (1,618 | ) | | | (1,584 | ) |
Total Accounts Receivable | | | 111,580 | | | | 162,586 | |
Fuel | | | 64,555 | | | | 72,882 | |
Materials and Supplies | | | 41,290 | | | | 42,033 | |
Emission Allowances | | | 26,461 | | | | 28,486 | |
Risk Management Assets | | | 22,221 | | | | 23,774 | |
Accrued Tax Benefits | | | 1,453 | | | | 8,797 | |
Regulatory Asset for Under-Recovered Fuel Costs | | | 19,199 | | | | - | |
Margin Deposits | | | 11,162 | | | | 14,762 | |
Prepayments and Other Current Assets | | | 11,066 | | | | 26,864 | |
TOTAL CURRENT ASSETS | | | 376,338 | | | | 437,155 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Generation | | | 2,719,642 | | | | 2,686,294 | |
Transmission | | | 676,250 | | | | 662,312 | |
Distribution | | | 1,804,501 | | | | 1,796,023 | |
Other Property, Plant and Equipment | | | 203,744 | | | | 203,593 | |
Construction Work in Progress | | | 142,609 | | | | 172,793 | |
Total Property, Plant and Equipment | | | 5,546,746 | | | | 5,521,015 | |
Accumulated Depreciation and Amortization | | | 1,959,482 | | | | 1,927,112 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 3,587,264 | | | | 3,593,903 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 303,741 | | | | 298,111 | |
Long-term Risk Management Assets | | | 23,080 | | | | 22,089 | |
Deferred Charges and Other Noncurrent Assets | | | 125,746 | | | | 152,932 | |
TOTAL OTHER NONCURRENT ASSETS | | | 452,567 | | | | 473,132 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 4,416,169 | | | $ | 4,504,190 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | | COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | CONDENSED CONSOLIDATED BALANCE SHEETS | | CONDENSED CONSOLIDATED BALANCE SHEETS | |
LIABILITIES AND SHAREHOLDER'S EQUITY | LIABILITIES AND SHAREHOLDER'S EQUITY | | LIABILITIES AND SHAREHOLDER'S EQUITY | |
September 30, 2010 and December 31, 2009 | | |
March 31, 2011 and December 31, 2010 | | March 31, 2011 and December 31, 2010 | |
(Unaudited) | (Unaudited) | | (Unaudited) | |
| | | | |
| | 2010 | | | 2009 | | | 2011 | | | 2010 | |
| | (in thousands) | | | (in thousands) | |
CURRENT LIABILITIES | | | | | | | | | | | | |
Advances from Affiliates | | $ | - | | | $ | 24,202 | | |
Accounts Payable: | | | | | | | | | | | | | | |
General | | | 83,817 | | | | 95,872 | | | $ | 80,031 | | | $ | 98,925 | |
Affiliated Companies | | | 54,380 | | | | 81,338 | | | | 55,640 | | | | 78,617 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 150,000 | | | | 150,000 | | | | 150,000 | | | | - | |
Long-term Debt Due Within One Year – Affiliated | | | - | | | | 100,000 | | |
Risk Management Liabilities | | | 15,500 | | | | 13,052 | | | | 13,053 | | | | 15,967 | |
Customer Deposits | | | 28,741 | | | | 27,911 | | | | 30,222 | | | | 29,441 | |
Accrued Taxes | | | 120,472 | | | | 199,001 | | | | 175,816 | | | | 226,572 | |
Accrued Interest | | | 27,283 | | | | 24,669 | | | | 25,189 | | | | 22,533 | |
Other Current Liabilities | | | 74,563 | | | | 67,053 | | | | 93,112 | | | | 111,868 | |
TOTAL CURRENT LIABILITIES | | | 554,756 | | | | 783,098 | | | | 623,063 | | | | 583,923 | |
| | | | | | | | | | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 1,438,753 | | | | 1,286,393 | | | | 1,288,900 | | | | 1,438,830 | |
Long-term Risk Management Liabilities | | | 9,389 | | | | 10,313 | | | | 7,653 | | | | 6,223 | |
Deferred Income Taxes | | | 556,710 | | | | 535,265 | | | | 619,951 | | | | 604,828 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 164,978 | | | | 174,671 | | | | 164,212 | | | | 163,888 | |
Employee Benefits and Pension Obligations | | | 125,982 | | | | 133,968 | | | | 135,202 | | | | 136,643 | |
Deferred Credits and Other Noncurrent Liabilities | | | 69,504 | | | | 65,963 | | | | 87,063 | | | | 83,640 | |
TOTAL NONCURRENT LIABILITIES | | | 2,365,316 | | | | 2,206,573 | | | | 2,302,981 | | | | 2,434,052 | |
| | | | | | | | | | | | | | | | |
TOTAL LIABILITIES | | | 2,920,072 | | | | 2,989,671 | | | | 2,926,044 | | | | 3,017,975 | |
| | | | | | | | | | | | | | | | |
Rate Matters (Note 3) | | | | | | | | | |
Commitments and Contingencies (Note 4) | | | | | | | | | |
Rate Matters (Note 2) | | | | | | | | | |
Commitments and Contingencies (Note 3) | | | | | | | | | |
| | | | | | | | | | | | | | | | |
COMMON SHAREHOLDER’S EQUITY | | | | | | | | | | | | | | | | |
Common Stock – No Par Value: | | | | | | | | | | | | | | | | |
Authorized – 24,000,000 Shares | | | | | | | | | | | | | | | | |
Outstanding – 16,410,426 Shares | | | 41,026 | | | | 41,026 | | | | 41,026 | | | | 41,026 | |
Paid-in Capital | | | 580,781 | | | | 580,663 | | | | 580,837 | | | | 580,812 | |
Retained Earnings | | | 921,344 | | | | 788,139 | | | | 918,746 | | | | 915,713 | |
Accumulated Other Comprehensive Income (Loss) | | | (48,993 | ) | | | (49,993 | ) | | | (50,484 | ) | | | (51,336 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | | 1,494,158 | | | | 1,359,835 | | | | 1,490,125 | | | | 1,486,215 | |
| | | | | | | | | | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY | | $ | 4,414,230 | | | $ | 4,349,506 | | | $ | 4,416,169 | | | $ | 4,504,190 | |
| | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | | See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | | COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | | CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |
For the Nine Months Ended September 30, 2010 and 2009 | | |
For the Three Months Ended March 31, 2011 and 2010 | | For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | (in thousands) | | (in thousands) | |
(Unaudited) | (Unaudited) | | (Unaudited) | |
| | | | |
| | 2010 | | | 2009 | | | 2011 | | | 2010 | |
OPERATING ACTIVITIES | | | | | | | | | | | | |
Net Income | | $ | 210,823 | | | $ | 230,629 | | | $ | 65,558 | | | $ | 51,650 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | | | | | | | | | |
Depreciation and Amortization | | | 113,733 | | | | 105,863 | | | | 41,426 | | | | 37,487 | |
Deferred Income Taxes | | | 30,333 | | | | 97,279 | | | | 31,902 | | | | 8,327 | |
Carrying Costs Income | | | (6,212 | ) | | | (5,394 | ) | |
Allowance for Equity Funds Used During Construction | | | (1,502 | ) | | | (2,799 | ) | | | (771 | ) | | | (921 | ) |
Mark-to-Market of Risk Management Contracts | | | (6,397 | ) | | | (14,832 | ) | | | (669 | ) | | | (11,609 | ) |
Property Taxes | | | 71,795 | | | | 67,012 | | | | 27,283 | | | | 24,131 | |
Fuel Over/Under-Recovery, Net | | | 22,912 | | | | (36,401 | ) | | | (4,891 | ) | | | 26,139 | |
Change in Other Noncurrent Assets | | | (5,506 | ) | | | (18,365 | ) | | | (9,041 | ) | | | (4,994 | ) |
Change in Other Noncurrent Liabilities | | | (14,413 | ) | | | 22,644 | | | | 5,100 | | | | (46 | ) |
Changes in Certain Components of Working Capital: | | | | | | | | | | | | | | | | |
Accounts Receivable, Net | | | 11,164 | | | | 62,244 | | | | 43,606 | | | | 5,553 | |
Fuel, Materials and Supplies | | | 6,419 | | | | (28,817 | ) | | | 10,033 | | | | (9,795 | ) |
Accounts Payable | | | (20,468 | ) | | | (56,723 | ) | | | (35,549 | ) | | | (22,402 | ) |
Customer Deposits | | | 830 | | | | (2,078 | ) | |
Accrued Taxes, Net | | | (49,443 | ) | | | (102,827 | ) | | | (48,059 | ) | | | (24,444 | ) |
Other Current Assets | | | 6,110 | | | | 8,017 | | | | 4,645 | | | | (428 | ) |
Other Current Liabilities | | | (1,049 | ) | | | (5,914 | ) | | | (25,526 | ) | | | (1,619 | ) |
Net Cash Flows from Operating Activities | | | 369,129 | | | | 319,538 | | | | 105,047 | | | | 77,029 | |
| | | | | | | | | | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | | | | | | | | | |
Construction Expenditures | | | (148,441 | ) | | | (216,737 | ) | | | (45,732 | ) | | | (42,906 | ) |
Change in Other Cash Deposits | | | 13,890 | | | | 12,223 | | | | - | | | | 10,290 | |
Change in Advances to Affiliates, Net | | | (182,225 | ) | | | - | | | | (9,504 | ) | | | (37,818 | ) |
Acquisitions of Assets | | | (586 | ) | | | (227 | ) | | | (201 | ) | | | (190 | ) |
Proceeds from Sales of Assets | | | 4,278 | | | | 721 | | | | 2,439 | | | | 789 | |
Other Investing Activities | | | | 12,179 | | | | - | |
Net Cash Flows Used for Investing Activities | | | (313,084 | ) | | | (204,020 | ) | | | (40,819 | ) | | | (69,835 | ) |
| | | | | | | | | | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | | | | | | | | | |
Issuance of Long-term Debt - Nonaffiliated | | | 149,443 | | | | 91,204 | | |
Issuance of Long-term Debt – Nonaffiliated | | | | - | | | | 149,625 | |
Change in Advances from Affiliates, Net | | | (24,202 | ) | | | (54,770 | ) | | | - | | | | (24,202 | ) |
Retirement of Long-term Debt - Affiliated | | | (100,000 | ) | | | - | | |
Retirement of Long-term Debt – Affiliated | | | | - | | | | (100,000 | ) |
Principal Payments for Capital Lease Obligations | | | (3,322 | ) | | | (2,017 | ) | | | (852 | ) | | | (1,120 | ) |
Dividends Paid on Common Stock | | | (77,500 | ) | | | (150,000 | ) | | | (62,500 | ) | | | (31,250 | ) |
Other Financing Activities | | | 119 | | | | 206 | | | | - | | | | 71 | |
Net Cash Flows Used for Financing Activities | | | (55,462 | ) | | | (115,377 | ) | | | (63,352 | ) | | | (6,876 | ) |
| | | | | | | | | | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 583 | | | | 141 | | | | 876 | | | | 318 | |
Cash and Cash Equivalents at Beginning of Period | | | 1,096 | | | | 1,063 | | | | 509 | | | | 1,096 | |
Cash and Cash Equivalents at End of Period | | $ | 1,679 | | | $ | 1,204 | | | $ | 1,385 | | | $ | 1,414 | |
| | | | | | | | | | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 59,840 | | | $ | 71,032 | | | $ | 16,396 | | | $ | 18,631 | |
Net Cash Paid for Income Taxes | | | 51,120 | | | | 10,997 | | | | 518 | | | | - | |
Noncash Acquisitions Under Capital Leases | | | 9,521 | | | | 784 | | | | 139 | | | | 8,353 | |
Construction Expenditures Included in Accounts Payable at September 30, | | | 12,561 | | | | 26,688 | | |
Noncash Dividend of Property to Parent | | | - | | | | 8,123 | | |
Government Grants Included in Accounts Receivable at March 31, | | | | 1,938 | | | | - | |
Construction Expenditures Included in Current Liabilities at March 31, | | | | 8,572 | | | | 13,891 | |
| | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | | See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
INDEX TOOF 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. The footnotes begin on page 161.143.
| Footnote Reference |
| |
Significant Accounting Matters | Note 1 |
New Accounting Pronouncements and Extraordinary Item | Note 2 |
Rate Matters | Note 32 |
| |
Commitments, Guarantees and Contingencies | Note 43 |
| |
Benefit Plans | Note 65 |
| |
Business Segments | Note 76 |
| |
Derivatives and Hedging | Note 87 |
| |
Fair Value Measurements | Note 98 |
| |
Income Taxes | Note 109 |
| |
Financing Activities | Note 1110 |
| |
Cost Reduction Initiatives | Note 1211 |
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS | |
| | | |
RESULTS OF OPERATIONS | | | |
| | | |
Third Quarter of 2010 Compared to Third Quarter of 2009 | |
| | | |
Reconciliation of Third Quarter of 2009 to Third Quarter of 2010 | |
Net Income | |
(in millions) | |
| | | |
Third Quarter of 2009 | | $ | 55 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins | | | 62 | |
FERC Municipals and Cooperatives | | | (5 | ) |
Off-system Sales | | | 6 | |
Other Revenues | | | (40 | ) |
Total Change in Gross Margin | | | 23 | |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | (6 | ) |
Taxes Other Than Income Taxes | | | (2 | ) |
Other Income | | | (1 | ) |
Interest Expense | | | (2 | ) |
Total Expenses and Other | | | (11 | ) |
| | | | |
Income Tax Expense | | | (5 | ) |
| | | | |
Third Quarter of 2010 | | $ | 62 | |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
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 $62 million primarily due to the following:
|
| | · | A $30 million increase in fuel margins primarily due to a $19 million increase in higher fuel and purchased power costs recorded in 2009 related to the Cook Plant Unit 1 (Unit 1) shutdown. This increase in fuel margins was offset by a corresponding decrease in Other Revenues as discussed below. |
| | · | A $25 million increase in weather-related usage for residential and commercial customers primarily due to a 130% increase in cooling degree days and increased demand. |
| | · | A $13 million increase in rate relief primarily due to the impact of the Michigan interim rate increase implemented in August 2010 and Indiana rate riders. |
| | These increases were partially offset by: |
| | · | An $8 million increase in PJM costs. |
| · | FERC Municipals and Cooperatives margins decreased $5 million primarily due to a unit power sales agreement ending in December 2009.
|
| · | Margins from Off-system Sales increased $6 million primarily due to increased prices and higher physical sales volumes, partially offset by lower trading and marketing margins.
|
| · | Other Revenues decreased $40 million primarily due to the following:
|
| | · | A $46 million decrease in the Cook Plant accidental outage insurance proceeds which ended when Unit 1 returned to service in December 2009. I&M reduced customer bills by approximately $19 million in the third quarter of 2009 for the cost of replacement power resulting from the Unit 1 outage. This decrease in insurance proceeds was offset by a corresponding increase in Retail Margins as discussed above. |
| | This decrease was partially offset by: |
| | · | A $5 million increase in River Transportation Division (RTD) revenues from barging activities. The increase in RTD revenue was partially offset by a corresponding increase in Other Operation and Maintenance expenses from barging activities as discussed below. |
Total Expenses and Other and Income Tax Expense changed between years as follows:
| | |
| · | Other Operation and Maintenance expenses increased $6 million primarily due to a $5 million increase in RTD expenses from barging activities. The increase in RTD expense was partially offset by a corresponding increase in Other Revenues from barging activities as discussed above.
| |
| · | Income Tax Expense increased $5 million primarily due to an increase in pretax book income.
| |
Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009 |
| | | | |
Reconciliation of Nine Months Ended September 30, 2009 to Nine Months Ended September 30, 2010 |
Net Income |
(in millions) |
| | | | |
Nine Months Ended September 30, 2009 | | $ | 184 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins | | | 142 | |
FERC Municipals And Cooperatives | | | (22) | |
Off-system Sales | | | 9 | |
Transmission Revenues | | | 2 | |
Other Revenues | | | (134) | |
Total Change in Gross Margin | | | (3) | |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | (75) | |
Depreciation and Amortization | | | (2) | |
Taxes Other Than Income Taxes | | | (3) | |
Other Income | | | 2 | |
Interest Expense | | | (5) | |
Total Expenses and Other | | | (83) | |
| | | | |
Income Tax Expense | | | 24 | |
| | | | |
Nine Months Ended September 30, 2010 | | $ | 122 | |
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 increased $142 million primarily due to the following:
|
| | · | A $70 million increase in fuel margins primarily due to a $59 million increase in higher fuel and purchased power costs recorded in 2009 related to the Unit 1 shutdown. This increase in fuel margins was offset by a corresponding decrease in Other Revenues as discussed below. |
| | · | A $42 million increase in weather-related usage and increased price for residential and commercial customers primarily due to a 101% increase in cooling degree days. |
| | · | A $25 million increase in rate relief primarily due to the impact of the Michigan interim rate increase implemented in August 2010 and the approval of the Indiana base rate filing effective March 2009. |
| | · | A $23 million increase in industrial sale margins due to higher usage reflecting an improvement in demand. |
| | These increases were partially offset by: |
| | · | A $13 million increase in PJM costs. |
| · | FERC Municipals and Cooperatives margins decreased $22 million primarily due to a unit power sales agreement ending in December 2009.
|
| · | Margins from Off-system Sales increased $9 million primarily due to increased prices and higher physical sales volumes, partially offset by lower trading and marketing margins.
|
| · | Other Revenues decreased $134 million primarily due to the following:
|
| | · | A $145 million decrease in the Cook Plant accidental outage insurance proceeds which ended when Unit 1 returned to service in December 2009. I&M reduced customer bills by approximately $59 million in the first nine months of 2009 for the cost of replacement power resulting from the Unit 1 outage. This decrease in insurance proceeds was offset by a corresponding increase in Retail Margins as discussed above. |
| | This decrease was partially offset by: |
| | · | A $10 million increase in River Transportation Division (RTD) revenues from barging activities. The increase in RTD revenue was offset by a corresponding increase in Other Operation and Maintenance expenses from barging activities as discussed below. |
Total Expenses and Other and Income Tax Expense changed between years as follows:
| · | Other Operation and Maintenance expenses increased $75 million primarily due to the following:
|
| | · | A $41 million increase due to expenses related to the cost reduction initiatives. |
| | · | An $11 million increase in RTD expenses from barging activities. The increase in RTD expense was partially offset by a corresponding increase in Other Revenues from barging activities as discussed above. |
| | · | A $10 million increase in transmission expense primarily due to lower credits under the Transmission Agreement. |
| | · | A $5 million increase in administrative and general expenses primarily due to an increase in benefit and insurance costs. |
| | · | A $4 million increase in distribution expenses associated with storm restoration expenses from June 2010 storms. |
| · | Taxes Other Than Income Taxes increased $3 million primarily due to expenses related to the cost reduction initiatives.
|
| · | Interest Expense increased $5 million related to the nuclear fuel financing.
|
| · | Income Tax Expense decreased $24 million primarily due to a decrease in pretax book income partially offset by the regulatory accounting treatment of state income taxes.
|
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS
EXECUTIVE OVERVIEW
REGULATORY ACTIVITY
Michigan Regulatory Activity
In October 2010, a settlement agreement was approved by the MPSC to increase annual base rates by $36 million based on a 10.35% return on common equity, effective December 2010, plus separate recovery of approximately $7 million of customer choice implementation costs over a two year period beginning April 2011. In addition, the approved revenue requirement includes the amortization of $6 million in previously expensed restructuring costs over five years, which I&M will defer and begin amortizing in the fourth quarter of 2010. Also, the approved settlement agreement provided for sharing of off-system sales margins between customers (75%) and I&M (25%) with customers receiving a credit in future Power Supply Cost Recovery proceedings for their jurisdictional share of any off-system sales margins. 60;See “Michigan Base Rate Filing” section of Note 3.
Cook Plant Unit 1 Fire and Shutdown
In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator. Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $395 million. Management believes that I&M should recover a significant portion of repair and replacement costs through the turbine vendor’s warranty, insurance and the regulatory process. I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power. The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors. As a result, the replacement of the repaired turbine rotors and other equip mentequipment is scheduled for the Unit 1 planned outage in the fall of 2011. If the ultimate costs of the incident are not covered by warranty, insurance or through the related regulatory process or if any future regulatory proceedings are adverse, it could reduce future net income and cash flows and impact financial condition. See “Indiana Fuel Clause Filing”“Michigan 2009 and “Michigan 20092010 Power Supply Cost Recovery Reconciliation” sectionsReconciliations” section of Note 32 and “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.3.
As a result of the nuclear plant situation in Japan following an earthquake, management expects the Nuclear Regulatory Commission and possibly Congress to review safety procedures and requirements for nuclear generating facilities. This review could increase procedures and testing requirements and increase future operating costs at the Cook Plant. LITIGATION AND ENVIRONMENTAL ISSUESLitigation and Environmental Issues
In the ordinary course of business, I&M 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 resolution will be or the timing and amount of any loss, fine or penalty may be. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss 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 20092010 Annual Report. Also, see Note 32 – Rate Matters and Note 43 – Commitments, Guarantees and Contingencies within the Condensed Notes to Conde nsedCondensed Financial Statements beginning on page 161.143. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.
See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 230201 for additional discussion of relevant factors.
RESULTS OF OPERATIONS | | | | | |
| | | | | | | |
KWH Sales/Degree Days | | | | | |
| | | | | | |
Summary of KWH Energy Sales |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in millions of KWH) |
Retail: | | | | | |
| Residential | | 1,836 | | | 1,765 |
| Commercial | | 1,263 | | | 1,208 |
| Industrial | | 1,844 | | | 1,800 |
| Miscellaneous | | 23 | | | 18 |
Total Retail | | 4,966 | | | 4,791 |
| | | | | |
Wholesale | | 2,096 | | | 1,906 |
| | | | | |
Total KWHs | | 7,062 | | | 6,697 |
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.
Summary of Heating and Cooling Degree Days |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in degree days) |
| | | | | | |
Actual - Heating (a) | | 2,392 | | | 2,174 |
Normal - Heating (b) | | 2,175 | | | 2,172 |
| | | | | | |
Actual - Cooling (c) | | - | | | - |
Normal - Cooling (b) | | 1 | | | 1 |
| | | | | | |
(a) | Eastern 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 cooling degree days are calculated on a 65 degree temperature base. |
First Quarter of 2011 Compared to First Quarter of 2010 |
| | | |
Reconciliation of First Quarter of 2010 to First Quarter of 2011 | |
Net Income | |
(in millions) | |
| | | |
First Quarter of 2010 | | $ | 45 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins | | | 13 | |
FERC Municipals and Cooperatives | | | 2 | |
Off-system Sales | | | 2 | |
Other Revenues | | | (2 | ) |
Total Change in Gross Margin | | | 15 | |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | (6 | ) |
Taxes Other Than Income Taxes | | | (1 | ) |
Other Income | | | (1 | ) |
Interest Expense | | | 1 | |
Total Expenses and Other | | | (7 | ) |
| | | | |
Income Tax Expense | | | (8 | ) |
| | | | |
First Quarter of 2011 | | $ | 45 | |
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 $13 million primarily due to the following: |
| · | An $8 million increase due to Michigan rate settlement effective in December 2010. |
| · | A $7 million increase in margins from residential sales primarily due to higher usage reflecting favorable weather. |
Total Expenses and Other and Income Tax Expense changed between years as follows:
· | Other Operation and Maintenance expenses increased $6 million primarily due to the following: |
| · | A $10 million increase in transmission expense primarily due to the Transmission Agreement modification effective November 2010. |
| This increase was partially offset by: |
| · | A $5 million decrease in administrative and general expenses. |
· | Income Tax Expense increased $8 million primarily due to an increase in pretax book income and federal income tax adjustments related to prior year tax returns. |
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 20092010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.
See the “New Accounting“Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230201 for a discussion of the adoption and impact of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK MANAGEMENT ACTIVITIES
See “Quantitative And Qualitative Disclosures About Risk Management Activities”Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230201 for a discussion of risk management activities.market risk.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | | INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF INCOME | CONDENSED CONSOLIDATED STATEMENTS OF INCOME | | CONDENSED CONSOLIDATED STATEMENTS OF INCOME | |
For the Three and Nine Months Ended September 30, 2010 and 2009 | | |
For the Three Months Ended March 31, 2011 and 2010 | | For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | (in thousands) | | (in thousands) | |
(Unaudited) | (Unaudited) | | (Unaudited) | |
| | |
| | Three Months Ended | | | Nine Months Ended | | | | | | | |
| | 2010 | | | 2009 | | | 2010 | | | 2009 | | | 2011 | | | 2010 | |
REVENUES | | | | | | | | | | | | | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 480,779 | | | $ | 435,399 | | | $ | 1,327,505 | | | $ | 1,257,673 | | | $ | 456,862 | | | $ | 438,024 | |
Sales to AEP Affiliates | | | 93,984 | | | | 43,796 | | | | 245,674 | | | | 161,167 | | | | 74,868 | | | | 84,217 | |
Other Revenues - Affiliated | | | 27,796 | | | | 24,958 | | | | 86,447 | | | | 80,890 | | | | 24,331 | | | | 27,966 | |
Other Revenues - Nonaffiliated | | | 5,691 | | | | 48,114 | | | | 11,595 | | | | 149,997 | | | | 4,431 | | | | 2,849 | |
TOTAL REVENUES | | | 608,250 | | | | 552,267 | | | | 1,671,221 | | | | 1,649,727 | | | | 560,492 | | | | 553,056 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
EXPENSES | | | | | | | | | | | | | | | | | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 134,721 | | | | 105,287 | | | | 356,160 | | | | 316,449 | | | | 115,062 | | | | 119,181 | |
Purchased Electricity for Resale | | | 27,904 | | | | 28,203 | | | | 89,115 | | | | 97,417 | | | | 29,292 | | | | 29,767 | |
Purchased Electricity from AEP Affiliates | | | 96,405 | | | | 93,093 | | | | 247,151 | | | | 253,964 | | | | 79,584 | | | | 82,250 | |
Other Operation | | | 132,200 | | | | 121,737 | | | | 425,859 | | | | 346,421 | | | | 133,211 | | | | 130,681 | |
Maintenance | | | 46,180 | | | | 50,650 | | | | 144,257 | | | | 148,412 | | | | 51,000 | | | | 48,444 | |
Depreciation and Amortization | | | 34,130 | | | | 34,032 | | | | 101,932 | | | | 100,406 | | | | 34,087 | | | | 33,831 | |
Taxes Other Than Income Taxes | | | 20,806 | | | | 19,122 | | | | 60,833 | | | | 58,071 | | | | 22,262 | | | | 21,032 | |
TOTAL EXPENSES | | | 492,346 | | | | 452,124 | | | | 1,425,307 | | | | 1,321,140 | | | | 464,498 | | | | 465,186 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 115,904 | | | | 100,143 | | | | 245,914 | | | | 328,587 | | | | 95,994 | | | | 87,870 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | | | | |
Interest Income | | | 1,079 | | | | 1,532 | | | | 2,598 | | | | 5,049 | | | | 696 | | | | 485 | |
Allowance for Equity Funds Used During Construction | | | 2,943 | | | | 3,492 | | | | 11,945 | | | | 7,830 | | | | 3,199 | | | | 4,435 | |
Interest Expense | | | (28,046 | ) | | | (25,668 | ) | | | (80,557 | ) | | | (75,372 | ) | | | (25,191 | ) | | | (26,101 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 91,880 | | | | 79,499 | | | | 179,900 | | | | 266,094 | | | | 74,698 | | | | 66,689 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Income Tax Expense | | | 29,580 | | | | 24,640 | | | | 57,940 | | | | 81,774 | | | | 29,271 | | | | 21,631 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
NET INCOME | | | 62,300 | | | | 54,859 | | | | 121,960 | | | | 184,320 | | | | 45,427 | | | | 45,058 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Preferred Stock Dividend Requirements | | | 85 | | | | 85 | | | | 255 | | | | 255 | | | | 85 | | | | 85 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
EARNINGS ATTRIBUTABLE TO COMMON STOCK | | $ | 62,215 | | | $ | 54,774 | | | $ | 121,705 | | | $ | 184,065 | | | $ | 45,342 | | | $ | 44,973 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
The common stock of I&M is wholly-owned by AEP. | | | | | | | | | | | | | | | | | The common stock of I&M is wholly-owned by AEP. | |
| | | | | | | | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | | See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | | INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S | CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S | | CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S | |
EQUITY AND COMPREHENSIVE INCOME (LOSS) | EQUITY AND COMPREHENSIVE INCOME (LOSS) | | EQUITY AND COMPREHENSIVE INCOME (LOSS) | |
For the Nine Months Ended September 30, 2010 and 2009 | | |
For the Three Months Ended March 31, 2011 and 2010 | | For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | (in thousands) | | (in thousands) | |
(Unaudited) | (Unaudited) | | (Unaudited) | |
| | | | |
| | | | | | | | | | | Accumulated | | | | | | | | | | | | | | | Accumulated | | | | |
| | | | | | | | | | | Other | | | | | | | | | | | | | | | Other | | | | |
| | Common | | | Paid-in | | | Retained | | | Comprehensive | | | | | | Common | | | Paid-in | | | Retained | | | Comprehensive | | | | |
| | Stock | | | Capital | | | Earnings | | | Income (Loss) | | | Total | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2008 | | $ | 56,584 | | | $ | 861,291 | | | $ | 538,637 | | | $ | (21,694 | ) | | $ | 1,434,818 | | |
| | | | | | | | | | | | | | | | | | | | | |
Capital Contribution from Parent | | | | | | | 120,000 | | | | | | | | | | | | 120,000 | | |
Common Stock Dividends | | | | | | | | | | | (73,500 | ) | | | | | | | (73,500 | ) | |
Preferred Stock Dividends | | | | | | | | | | | (255 | ) | | | | | | | (255 | ) | |
Gain on Reacquired Preferred Stock | | | | | | | 1 | | | | | | | | | | | | 1 | | |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 1,481,064 | | |
| | | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of | | | | | | | | | | | | | | | | | | | | | |
Taxes: | | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $265 | | | | | | | | | | | | | | | (492 | ) | | | (492 | ) | |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $334 | | | | | | | | | | | | | | | 620 | | | | 620 | | |
NET INCOME | | | | | | | | | | | 184,320 | | | | | | | | 184,320 | | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 184,448 | | |
| | | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | |
EQUITY – SEPTEMBER 30, 2009 | | $ | 56,584 | | | $ | 981,292 | | | $ | 649,202 | | | $ | (21,566 | ) | | $ | 1,665,512 | | |
| | | | | | | | | | | | | | | | | | | | | | Stock | | | Capital | | | Earnings | | | Income (Loss) | | | Total | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2009 | | $ | 56,584 | | | $ | 981,292 | | | $ | 656,608 | | | $ | (21,701 | ) | | $ | 1,672,783 | | | $ | 56,584 | | | $ | 981,292 | | | $ | 656,608 | | | $ | (21,701 | ) | | $ | 1,672,783 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (78,250 | ) | | | | | | | (78,250 | ) | | | | | | | | | | | (25,750 | ) | | | | | | | (25,750 | ) |
Preferred Stock Dividends | | | | | | | | | | | (255 | ) | | | | | | | (255 | ) | | | | | | | | | | | (85 | ) | | | | | | | (85 | ) |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 1,594,278 | | | | | | | | | | | | | | | | | | | | 1,646,948 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Taxes: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $77 | | | | | | | | | | | | | | | (144 | ) | | | (144 | ) | |
Cash Flow Hedges, Net of Tax of $422 | | | | | | | | | | | | | | | | (784 | ) | | | (784 | ) |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $352 | | | | | | | | | | | | | | | 655 | | | | 655 | | |
Costs, Net of Tax of $117 | | | | | | | | | | | | | | | | 218 | | | | 218 | |
NET INCOME | | | | | | | | | | | 121,960 | | | | | | | | 121,960 | | | | | | | | | | | | 45,058 | | | | | | | | 45,058 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 122,471 | | | | | | | | | | | | | | | | | | | | 44,492 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
EQUITY – SEPTEMBER 30, 2010 | | $ | 56,584 | | | $ | 981,292 | | | $ | 700,063 | | | $ | (21,190 | ) | | $ | 1,716,749 | | |
EQUITY – MARCH 31, 2010 | | | $ | 56,584 | | | $ | 981,292 | | | $ | 675,831 | | | $ | (22,267 | ) | | $ | 1,691,440 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2010 | | | $ | 56,584 | | | $ | 981,294 | | | $ | 677,360 | | | $ | (20,889 | ) | | $ | 1,694,349 | |
| | | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | | (18,750 | ) | | | | | | | (18,750 | ) |
Preferred Stock Dividends | | | | | | | | | | | | (85 | ) | | | | | | | (85 | ) |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | | 1,675,514 | |
| | | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $286 | | | | | | | | | | | | | | | | 531 | | | | 531 | |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $128 | | | | | | | | | | | | | | | | 237 | | | | 237 | |
NET INCOME | | | | | | | | | | | | 45,427 | | | | | | | | 45,427 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | 46,195 | |
| | | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | |
EQUITY – MARCH 31, 2011 | | | $ | 56,584 | | | $ | 981,294 | | | $ | 703,952 | | | $ | (20,121 | ) | | $ | 1,721,709 | |
| | | | | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | | See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
ASSETS | |
September 30, 2010 and December 31, 2009 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2010 | | | 2009 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 789 | | | $ | 779 | |
Advances to Affiliates | | | 192,779 | | | | 114,012 | |
Accounts Receivable: | | | | | | | | |
Customers | | | 63,520 | | | | 71,120 | |
Affiliated Companies | | | 84,372 | | | | 83,248 | |
Accrued Unbilled Revenues | | | 7,357 | | | | 8,762 | |
Miscellaneous | | | 11,545 | | | | 8,638 | |
Allowance for Uncollectible Accounts | | | (2,105 | ) | | | (2,265 | ) |
Total Accounts Receivable | | | 164,689 | | | | 169,503 | |
Fuel | | | 95,096 | | | | 79,554 | |
Materials and Supplies | | | 160,921 | | | | 164,439 | |
Risk Management Assets | | | 39,717 | | | | 34,438 | |
Accrued Tax Benefits | | | 59,764 | | | | 144,473 | |
Deferred Cook Plant Fire Costs | | | 52,507 | | | | 134,322 | |
Prepayments and Other Current Assets | | | 24,940 | | | | 29,395 | |
TOTAL CURRENT ASSETS | | | 791,202 | | | | 870,915 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Production | | | 3,713,372 | | | | 3,634,215 | |
Transmission | | | 1,172,639 | | | | 1,154,026 | |
Distribution | | | 1,398,319 | | | | 1,360,553 | |
Other Property, Plant and Equipment (including nuclear fuel and coal mining) | | | 761,286 | | | | 755,132 | |
Construction Work in Progress | | | 306,628 | | | | 278,278 | |
Total Property, Plant and Equipment | | | 7,352,244 | | | | 7,182,204 | |
Accumulated Depreciation, Depletion and Amortization | | | 3,125,414 | | | | 3,073,695 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 4,226,830 | | | | 4,108,509 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 507,358 | | | | 496,464 | |
Spent Nuclear Fuel and Decommissioning Trusts | | | 1,465,699 | | | | 1,391,919 | |
Long-term Risk Management Assets | | | 41,500 | | | | 29,134 | |
Deferred Charges and Other Noncurrent Assets | | | 68,998 | | | | 82,047 | |
TOTAL OTHER NONCURRENT ASSETS | | | 2,083,555 | | | | 1,999,564 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 7,101,587 | | | $ | 6,978,988 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
LIABILITIES AND SHAREHOLDERS' EQUITY | |
September 30, 2010 and December 31, 2009 | |
(dollars in thousands) | |
(Unaudited) | |
| |
CURRENT LIABILITIES | | 2010 | | | 2009 | |
Accounts Payable: | | | | | | |
General | | $ | 103,098 | | | $ | 171,192 | |
Affiliated Companies | | | 64,027 | | | | 61,315 | |
Long-term Debt Due Within One Year - Nonaffiliated | | | | | | | | |
(September 30, 2010 amount includes $61,435 related to DCC Fuel) | | | 211,435 | | | | 37,544 | |
Long-term Debt Due Within One Year – Affiliated | | | - | | | | 25,000 | |
Risk Management Liabilities | | | 16,055 | | | | 13,436 | |
Customer Deposits | | | 28,615 | | | | 27,711 | |
Accrued Taxes | | | 42,622 | | | | 56,814 | |
Accrued Interest | | | 23,451 | | | | 27,633 | |
Obligations Under Capital Leases | | | 14,306 | | | | 25,065 | |
Other Current Liabilities | | | 163,013 | | | | 126,800 | |
TOTAL CURRENT LIABILITIES | | | 666,622 | | | | 572,510 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 1,907,476 | | | | 2,015,362 | |
Long-term Risk Management Liabilities | | | 9,713 | | | | 10,386 | |
Deferred Income Taxes | | | 752,172 | | | | 696,163 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 818,084 | | | | 756,845 | |
Asset Retirement Obligations | | | 935,586 | | | | 894,746 | |
Deferred Credits and Other Noncurrent Liabilities | | | 287,109 | | | | 352,116 | |
TOTAL NONCURRENT LIABILITIES | | | 4,710,140 | | | | 4,725,618 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 5,376,762 | | | | 5,298,128 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 8,076 | | | | 8,077 | |
| | | | | | | | |
Rate Matters (Note 3) | | | | | | | | |
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 | | | 981,292 | | | | 981,292 | |
Retained Earnings | | | 700,063 | | | | 656,608 | |
Accumulated Other Comprehensive Income (Loss) | | | (21,190 | ) | | | (21,701 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | | 1,716,749 | | | | 1,672,783 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 7,101,587 | | | $ | 6,978,988 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
ASSETS | |
March 31, 2011 and December 31, 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 912 | | | $ | 361 | |
Advances to Affiliates | | | 56,813 | | | | - | |
Accounts Receivable: | | | | | | | | |
Customers | | | 56,396 | | | | 76,193 | |
Affiliated Companies | | | 62,023 | | | | 149,169 | |
Accrued Unbilled Revenues | | | 28,066 | | | | 19,449 | |
Miscellaneous | | | 11,714 | | | | 10,968 | |
Allowance for Uncollectible Accounts | | | (1,687 | ) | | | (1,692 | ) |
Total Accounts Receivable | | | 156,512 | | | | 254,087 | |
Fuel | | | 79,584 | | | | 87,551 | |
Materials and Supplies | | | 177,955 | | | | 178,331 | |
Risk Management Assets | | | 26,436 | | | | 27,526 | |
Accrued Tax Benefits | | | 68,504 | | | | 71,113 | |
Deferred Cook Plant Fire Costs | | | 46,532 | | | | 45,752 | |
Prepayments and Other Current Assets | | | 24,607 | | | | 33,713 | |
TOTAL CURRENT ASSETS | | | 637,855 | | | | 698,434 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Generation | | | 3,781,344 | | | | 3,774,262 | |
Transmission | | | 1,197,343 | | | | 1,188,665 | |
Distribution | | | 1,427,078 | | | | 1,411,095 | |
Other Property, Plant and Equipment (including nuclear fuel and coal mining) | | | 715,565 | | | | 719,708 | |
Construction Work in Progress | | | 301,781 | | | | 301,534 | |
Total Property, Plant and Equipment | | | 7,423,111 | | | | 7,395,264 | |
Accumulated Depreciation, Depletion and Amortization | | | 3,153,696 | | | | 3,124,998 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 4,269,415 | | | | 4,270,266 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 534,389 | | | | 556,254 | |
Spent Nuclear Fuel and Decommissioning Trusts | | | 1,558,535 | | | | 1,515,227 | |
Long-term Risk Management Assets | | | 31,923 | | | | 31,485 | |
Deferred Charges and Other Noncurrent Assets | | | 85,384 | | | | 77,229 | |
TOTAL OTHER NONCURRENT ASSETS | | | 2,210,231 | | | | 2,180,195 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 7,117,501 | | | $ | 7,148,895 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
| | | | | | | | |
| | | | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
LIABILITIES AND SHAREHOLDERS' EQUITY | |
March 31, 2011 and December 31, 2010 | |
(dollars in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
CURRENT LIABILITIES | | | | | | |
Advances from Affiliates | | $ | - | | | $ | 42,769 | |
Accounts Payable: | | | | | | | | |
General | | | 84,677 | | | | 121,665 | |
Affiliated Companies | | | 69,464 | | | | 105,221 | |
Long-term Debt Due Within One Year - Nonaffiliated | | | | | | | | |
(March 31, 2011 and December 31, 2010 amounts include $78,332 and $77,457, | | | | | | | | |
respectively, related to DCC Fuel) | | | 155,332 | | | | 154,457 | |
Risk Management Liabilities | | | 13,663 | | | | 16,785 | |
Customer Deposits | | | 29,240 | | | | 29,264 | |
Accrued Taxes | | | 78,574 | | | | 62,637 | |
Accrued Interest | | | 23,045 | | | | 27,444 | |
Other Current Liabilities | | | 142,392 | | | | 140,710 | |
TOTAL CURRENT LIABILITIES | | | 596,387 | | | | 700,952 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 1,843,771 | | | | 1,849,769 | |
Long-term Risk Management Liabilities | | | 7,992 | | | | 6,530 | |
Deferred Income Taxes | | | 780,312 | | | | 760,105 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 866,458 | | | | 852,197 | |
Asset Retirement Obligations | | | 974,935 | | | | 963,029 | |
Deferred Credits and Other Noncurrent Liabilities | | | 317,865 | | | | 313,892 | |
TOTAL NONCURRENT LIABILITIES | | | 4,791,333 | | | | 4,745,522 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 5,387,720 | | | | 5,446,474 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 8,072 | | | | 8,072 | |
| | | | | | | | |
Rate Matters (Note 2) | | | | | | | | |
Commitments and Contingencies (Note 3) | | | | | | | | |
| | | | | | | | |
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 | | | 981,294 | | | | 981,294 | |
Retained Earnings | | | 703,952 | | | | 677,360 | |
Accumulated Other Comprehensive Income (Loss) | | | (20,121 | ) | | | (20,889 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | | 1,721,709 | | | | 1,694,349 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 7,117,501 | | | $ | 7,148,895 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | | INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | | CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |
For the Nine Months Ended September 30, 2010 and 2009 | | |
For the Three Months Ended March 31, 2011 and 2010 | | For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | (in thousands) | | (in thousands) | |
(Unaudited) | (Unaudited) | | (Unaudited) | |
| | | | |
| | 2010 | | | 2009 | | | 2011 | | | 2010 | |
OPERATING ACTIVITIES | | | | | | | | | | | | |
Net Income | | $ | 121,960 | | | $ | 184,320 | | | $ | 45,427 | | | $ | 45,058 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | | | | | | | | | |
Depreciation and Amortization | | | 101,932 | | | | 100,406 | | | | 34,087 | | | | 33,831 | |
Deferred Income Taxes | | | 40,125 | | | | 133,959 | | | | 25,087 | | | | 18,442 | |
Deferral of Incremental Nuclear Refueling Outage Expenses, Net | | | (12,323 | ) | | | (4,563 | ) | |
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net | | | | 11,616 | | | | (20,025 | ) |
Allowance for Equity Funds Used During Construction | | | (11,945 | ) | | | (7,830 | ) | | | (3,199 | ) | | | (4,435 | ) |
Mark-to-Market of Risk Management Contracts | | | (16,887 | ) | | | (14,580 | ) | | | (658 | ) | | | (20,345 | ) |
Amortization of Nuclear Fuel | | | 113,031 | | | | 41,198 | | | | 34,240 | | | | 30,090 | |
Pension Contributions to Qualified Plan Trust | | | (66,711 | ) | | | - | | |
Fuel Over/Under Recovery, Net | | | (280 | ) | | | 20,588 | | | | 4,156 | | | | 16,439 | |
Change in Other Noncurrent Assets | | | 20,044 | | | | 285 | | | | (6,066 | ) | | | (11,056 | ) |
Change in Other Noncurrent Liabilities | | | 63,409 | | | | 50,932 | | | | 13,327 | | | | 28,926 | |
Changes in Certain Components of Working Capital: | | | | | | | | | | | | | | | | |
Accounts Receivable, Net | | | 4,814 | | | | (2,322 | ) | | | 97,575 | | | | 28,078 | |
Fuel, Materials and Supplies | | | (12,021 | ) | | | (1,591 | ) | | | 8,343 | | | | (18,972 | ) |
Accounts Payable | | | (10,928 | ) | | | (48,044 | ) | | | (71,206 | ) | | | 13,171 | |
Accrued Taxes, Net | | | 72,156 | | | | (15,005 | ) | | | 14,479 | | | | 23,964 | |
Received (Deferred) Cook Plant Fire Costs | | | 63,247 | | | | (69,921 | ) | |
Other Current Assets | | | 408 | | | | (7,208 | ) | | | (1,475 | ) | | | (13,044 | ) |
Other Current Liabilities | | | 14,671 | | | | (18,278 | ) | | | 3,865 | | | | 38,068 | |
Net Cash Flows from Operating Activities | | | 484,702 | | | | 342,346 | | | | 209,598 | | | | 188,190 | |
| | | | | | | | | | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | | | | | | | | | |
Construction Expenditures | | | (224,488 | ) | | | (242,256 | ) | | | (54,733 | ) | | | (104,796 | ) |
Change in Advances to Affiliates, Net | | | (78,767 | ) | | | (160,749 | ) | | | (56,813 | ) | | | 28,826 | |
Purchases of Investment Securities | | | (1,128,747 | ) | | | (571,167 | ) | | | (305,945 | ) | | | (247,632 | ) |
Sales of Investment Securities | | | 1,087,484 | | | | 523,927 | | | | 287,761 | | | | 232,078 | |
Acquisitions of Nuclear Fuel | | | (69,459 | ) | | | (153,172 | ) | | | (27,132 | ) | | | (37,616 | ) |
Other Investing Activities | | | (6,213 | ) | | | 18,990 | | | | 17,029 | | | | 500 | |
Net Cash Flows Used for Investing Activities | | | (420,190 | ) | | | (584,427 | ) | | | (139,833 | ) | | | (128,640 | ) |
| | | | | | | | | | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | | | | | | | | | |
Capital Contribution from Parent | | | - | | | | 120,000 | | |
Issuance of Long-term Debt - Nonaffiliated | | | 84,564 | | | | 670,060 | | | | 76,864 | | | | - | |
Issuance of Long-term Debt - Affiliated | | | - | | | | 25,000 | | |
Change in Advances from Affiliates, Net | | | - | | | | (476,036 | ) | | | (42,769 | ) | | | - | |
Retirement of Long-term Debt - Nonaffiliated | | | (19,208 | ) | | | - | | | | (82,354 | ) | | | - | |
Retirement of Long-term Debt - Affiliated | | | (25,000 | ) | | | - | | | | - | | | | (25,000 | ) |
Retirement of Cumulative Preferred Stock | | | (1 | ) | | | (2 | ) | |
Principal Payments for Capital Lease Obligations | | | (26,785 | ) | | | (23,640 | ) | | | (2,128 | ) | | | (8,524 | ) |
Dividends Paid on Common Stock | | | (78,250 | ) | | | (73,500 | ) | | | (18,750 | ) | | | (25,750 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (255 | ) | | | (255 | ) | | | (85 | ) | | | (85 | ) |
Other Financing Activities | | | 433 | | | | 569 | | | | 8 | | | | 24 | |
Net Cash Flows from (Used for) Financing Activities | | | (64,502 | ) | | | 242,196 | | |
Net Cash Flows Used for Financing Activities | | | | (69,214 | ) | | | (59,335 | ) |
| | | | | | | | | | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 10 | | | | 115 | | | | 551 | | | | 215 | |
Cash and Cash Equivalents at Beginning of Period | | | 779 | | | | 728 | | | | 361 | | | | 779 | |
Cash and Cash Equivalents at End of Period | | $ | 789 | | | $ | 843 | | | $ | 912 | | | $ | 994 | |
| | | | | | | | | | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 81,576 | | | $ | 81,833 | | | $ | 28,542 | | | $ | 30,056 | |
Net Cash Paid (Received) for Income Taxes | | | (66,680 | ) | | | (21,414 | ) | | | (1,033 | ) | | | - | |
Noncash Acquisitions Under Capital Leases | | | 9,708 | | | | 2,344 | | | | 693 | | | | 8,476 | |
Construction Expenditures Included in Accounts Payable at September 30, | | | 19,690 | | | | 42,576 | | |
Acquisition of Nuclear Fuel Included in Current Liabilities at September 30, | | | 20,332 | | | | 2 | | |
Construction Expenditures Included in Current Liabilities at March 31, | | | | 21,651 | | | | 29,496 | |
Acquisition of Nuclear Fuel Included in Current Liabilities at March 31, | | | | 377 | | | | 2,705 | |
| | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | | See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX TOOF 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. The footnotes begin on page 161.143.
| Footnote Reference |
| |
Significant Accounting Matters | Note 1 |
New Accounting Pronouncements and Extraordinary Item | Note 2 |
Rate Matters | Note 32 |
| |
Commitments, Guarantees and Contingencies | Note 43 |
| |
Benefit Plans | Note 65 |
| |
Business Segments | Note 76 |
| |
Derivatives and Hedging | Note 87 |
| |
Fair Value Measurements | Note 98 |
| |
Income Taxes | Note 109 |
| |
Financing Activities | Note 1110 |
| |
Cost Reduction Initiatives | Note 1211 |
OHIOFinancing Activities
Net Cash Flows from Financing Activities were $243 million in 2011. APCo issued $350 million of Senior Unsecured Notes and $295 million of Pollution Control Bonds, partially offset by the retirement of $230 million of Pollution Control Bonds. APCo had a net decrease of $128 million in borrowings from the Utility Money Pool. In addition, APCo paid $38 million in common stock dividends.
Net Cash Flows Used for Financing Activities were $10 million in 2010. APCo had a net increase of $118 million in borrowings from the Utility Money Pool. APCo retired $100 million of Notes Payable - Affiliated and issued $17.5 million of Pollution Control Bonds in 2010. In addition, APCo paid $44 million in common stock dividends.
In April 2011, APCo retired $250 million of 5.55% Senior Unsecured Notes due in 2011.
Long-term debt issuances, retirements and principal payments made during the first three months of 2011 were:
Issuances | | | | | | | | |
| | | Principal | | Interest | | Due |
| Type of Debt | | Amount | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| Senior Unsecured Notes | | $ | 350,000 | | 4.60 | | 2021 |
| Pollution Control Bonds | | | 65,350 | | 2.00 | | 2012 |
| Pollution Control Bonds | | | 75,000 | (a) | Variable | | 2036 |
| Pollution Control Bonds | | | 50,275 | (a) | Variable | | 2036 |
| Pollution Control Bonds | | | 54,375 | (a) | Variable | | 2042 |
| Pollution Control Bonds | | | 50,000 | (a) | Variable | | 2042 |
| (a) | These pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on APCo’s Condensed Consolidated Balance Sheets. |
Retirements and Principal Payments | | | | | | | |
| | | Principal | | Interest | | Due |
| Type of Debt | | Amount Paid | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| Pollution Control Bonds | | $ | 75,000 | | Variable | | 2036 |
| Pollution Control Bonds | | | 50,275 | | Variable | | 2036 |
| Pollution Control Bonds | | | 54,375 | | Variable | | 2042 |
| Pollution Control Bonds | | | 50,000 | | Variable | | 2042 |
| Land Note | | | 5 | | 13.718 | | 2026 |
CONTRACTUAL OBLIGATION INFORMATION
A summary of contractual obligations is included in the 2010 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.
See the “Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 201 for a discussion of accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See “Quantitative And Qualitative Disclosures About Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 201 for a discussion of market risk.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF INCOME | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| | | | | | |
| | 2011 | | | 2010 | |
REVENUES | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 751,012 | | | $ | 845,990 | |
Sales to AEP Affiliates | | | 78,691 | | | | 78,771 | |
Other Revenues | | | 2,117 | | | | 1,862 | |
TOTAL REVENUES | | | 831,820 | | | | 926,623 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 180,581 | | | | 180,640 | |
Purchased Electricity for Resale | | | 69,218 | | | | 63,683 | |
Purchased Electricity from AEP Affiliates | | | 224,189 | | | | 267,502 | |
Other Operation | | | 113,276 | | | | 90,040 | |
Maintenance | | | 32,293 | | | | 63,110 | |
Depreciation and Amortization | | | 69,099 | | | | 77,430 | |
Taxes Other Than Income Taxes | | | 27,103 | | | | 26,280 | |
TOTAL EXPENSES | | | 715,759 | | | | 768,685 | |
| | | | | | | | |
OPERATING INCOME | | | 116,061 | | | | 157,938 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest Income | | | 320 | | | | 291 | |
Carrying Costs Income | | | 3,439 | | | | 5,764 | |
Allowance for Equity Funds Used During Construction | | | 883 | | | | 1,163 | |
Interest Expense | | | (52,939 | ) | | | (51,727 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 67,764 | | | | 113,429 | |
| | | | | | | | |
Income Tax Expense | | | 28,784 | | | | 43,147 | |
| | | | | | | | |
NET INCOME | | | 38,980 | | | | 70,282 | |
| | | | | | | | |
Preferred Stock Dividend Requirements Including Capital Stock Expense | | | 200 | | | | 225 | |
| | | | | | | | |
EARNINGS ATTRIBUTABLE TO COMMON STOCK | | $ | 38,780 | | | $ | 70,057 | |
| |
The common stock of APCo is wholly-owned by AEP. | |
| |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S | |
EQUITY AND COMPREHENSIVE INCOME (LOSS) | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | | | | | | | | | | Accumulated | | | | |
| | | | | | | | | | | Other | | | | |
| | Common | | | Paid-in | | | Retained | | | Comprehensive | | | | |
| | Stock | | | Capital | | | Earnings | | | Income (Loss) | | | Total | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2009 | | $ | 260,458 | | | $ | 1,475,393 | | | $ | 1,085,980 | | | $ | (50,254 | ) | | $ | 2,771,577 | |
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (44,000 | ) | | | | | | | (44,000 | ) |
Preferred Stock Dividends | | | | | | | | | | | (200 | ) | | | | | | | (200 | ) |
Capital Stock Expense | | | | | | | 27 | | | | (25 | ) | | | | | | | 2 | |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 2,727,379 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of | | | | | | | | | | | | | | | | | | | | |
Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $940 | | | | | | | | | | | | | | | (1,746 | ) | | | (1,746 | ) |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $562 | | | | | | | | | | | | | | | 1,043 | | | | 1,043 | |
NET INCOME | | | | | | | | | | | 70,282 | | | | | | | | 70,282 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 69,579 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – MARCH 31, 2010 | | $ | 260,458 | | | $ | 1,475,420 | | | $ | 1,112,037 | | | $ | (50,957 | ) | | $ | 2,796,958 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2010 | | $ | 260,458 | | | $ | 1,475,496 | | | $ | 1,133,748 | | | $ | (48,023 | ) | | $ | 2,821,679 | |
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (37,500 | ) | | | | | | | (37,500 | ) |
Preferred Stock Dividends | | | | | | | | | | | (200 | ) | | | | | | | (200 | ) |
Capital Stock Expense | | | | | | | 3 | | | | | | | | | | | | 3 | |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 2,783,982 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of | | | | | | | | | | | | | | | | | | | | |
Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $275 | | | | | | | | | | | | | | | 511 | | | | 511 | |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $418 | | | | | | | | | | | | | | | 777 | | | | 777 | |
NET INCOME | | | | | | | | | | | 38,980 | | | | | | | | 38,980 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 40,268 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – MARCH 31, 2011 | | $ | 260,458 | | | $ | 1,475,499 | | | $ | 1,135,028 | | | $ | (46,735 | ) | | $ | 2,824,250 | |
| |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
ASSETS | |
March 31, 2011 and December 31, 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 2,384 | | | $ | 951 | |
Advances to Affiliates | | | 383,537 | | | | - | |
Accounts Receivable: | | | | | | | | |
Customers | | | 153,002 | | | | 166,878 | |
Affiliated Companies | | | 101,346 | | | | 145,972 | |
Accrued Unbilled Revenues | | | 58,693 | | | | 108,210 | |
Miscellaneous | | | 1,348 | | | | 3,090 | |
Allowance for Uncollectible Accounts | | | (7,045 | ) | | | (6,667 | ) |
Total Accounts Receivable | | | 307,344 | | | | 417,483 | |
Fuel | | | 167,153 | | | | 230,697 | |
Materials and Supplies | | | 91,068 | | | | 89,370 | |
Risk Management Assets | | | 38,923 | | | | 53,242 | |
Accrued Tax Benefits | | | 109,294 | | | | 104,435 | |
Regulatory Asset for Under-Recovered Fuel Costs | | | 18,131 | | | | 18,300 | |
Prepayments and Other Current Assets | | | 29,707 | | | | 35,811 | |
TOTAL CURRENT ASSETS | | | 1,147,541 | | | | 950,289 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Generation | | | 5,096,419 | | | | 4,736,150 | |
Transmission | | | 1,874,320 | | | | 1,852,415 | |
Distribution | | | 2,760,683 | | | | 2,740,752 | |
Other Property, Plant and Equipment | | | 348,613 | | | | 348,013 | |
Construction Work in Progress | | | 209,978 | | | | 562,280 | |
Total Property, Plant and Equipment | | | 10,290,013 | | | | 10,239,610 | |
Accumulated Depreciation and Amortization | | | 2,882,681 | | | | 2,843,087 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 7,407,332 | | | | 7,396,523 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 1,485,103 | | | | 1,486,625 | |
Long-term Risk Management Assets | | | 40,266 | | | | 38,420 | |
Deferred Charges and Other Noncurrent Assets | | | 128,641 | | | | 125,296 | |
TOTAL OTHER NONCURRENT ASSETS | | | 1,654,010 | | | | 1,650,341 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 10,208,883 | | | $ | 9,997,153 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
LIABILITIES AND SHAREHOLDERS' EQUITY | |
March 31, 2011 and December 31, 2010 | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
| | (in thousands) | |
CURRENT LIABILITIES | | | | | | |
Advances from Affiliates | | $ | - | | | $ | 128,331 | |
Accounts Payable: | | | | | | | | |
General | | | 155,890 | | | | 223,144 | |
Affiliated Companies | | | 133,716 | | | | 166,884 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 479,673 | | | | 479,672 | |
Risk Management Liabilities | | | 22,746 | | | | 27,993 | |
Customer Deposits | | | 59,385 | | | | 58,451 | |
Deferred Income Taxes | | | 40,752 | | | | 44,180 | |
Accrued Taxes | | | 76,268 | | | | 75,619 | |
Accrued Interest | | | 71,566 | | | | 57,871 | |
Other Current Liabilities | | | 81,662 | | | | 93,286 | |
TOTAL CURRENT LIABILITIES | | | 1,121,658 | | | | 1,355,431 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 3,496,032 | | | | 3,081,469 | |
Long-term Risk Management Liabilities | | | 13,339 | | | | 10,873 | |
Deferred Income Taxes | | | 1,679,963 | | | | 1,642,072 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 554,577 | | | | 562,381 | |
Employee Benefits and Pension Obligations | | | 302,517 | | | | 306,460 | |
Deferred Credits and Other Noncurrent Liabilities | | | 198,811 | | | | 199,041 | |
TOTAL NONCURRENT LIABILITIES | | | 6,245,239 | | | | 5,802,296 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 7,366,897 | | | | 7,157,727 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 17,736 | | | | 17,747 | |
| | | | | | | | |
Rate Matters (Note 2) | | | | | | | | |
Commitments and Contingencies (Note 3) | | | | | | | | |
| | | | | | | | |
COMMON SHAREHOLDER’S EQUITY | | | | | | | | |
Common Stock – No Par Value: | | | | | | | | |
Authorized – 30,000,000 Shares | | | | | | | | |
Outstanding – 13,499,500 Shares | | | 260,458 | | | | 260,458 | |
Paid-in Capital | | | 1,475,499 | | | | 1,475,496 | |
Retained Earnings | | | 1,135,028 | | | | 1,133,748 | |
Accumulated Other Comprehensive Income (Loss) | | | (46,735 | ) | | | (48,023 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | | 2,824,250 | | | | 2,821,679 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 10,208,883 | | | $ | 9,997,153 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 38,980 | | | $ | 70,282 | |
Adjustments to Reconcile Net Income to Net Cash Flows from | | | | | | | | |
Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 69,099 | | | | 77,430 | |
Deferred Income Taxes | | | 60,802 | | | | 19,121 | |
Carrying Costs Income | | | (3,439 | ) | | | (5,764 | ) |
Allowance for Equity Funds Used During Construction | | | (883 | ) | | | (1,163 | ) |
Mark-to-Market of Risk Management Contracts | | | (1,553 | ) | | | (12,977 | ) |
Fuel Over/Under-Recovery, Net | | | (9,857 | ) | | | (11,804 | ) |
Change in Other Noncurrent Assets | | | 10,237 | | | | 11,082 | |
Change in Other Noncurrent Liabilities | | | 12,013 | | | | (2,568 | ) |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 109,662 | | | | 80,813 | |
Fuel, Materials and Supplies | | | 61,846 | | | | 41,054 | |
Accounts Payable | | | (71,056 | ) | | | (97,732 | ) |
Accrued Taxes, Net | | | (32,472 | ) | | | 24,150 | |
Other Current Assets | | | 6,505 | | | | (4,250 | ) |
Other Current Liabilities | | | 957 | | | | (9,152 | ) |
Net Cash Flows from Operating Activities | | | 250,841 | | | | 178,522 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (113,132 | ) | | | (167,412 | ) |
Change in Advances to Affiliates, Net | | | (383,537 | ) | | | - | |
Other Investing Activities | | | 4,047 | | | | (566 | ) |
Net Cash Flows Used for Investing Activities | | | (492,622 | ) | | | (167,978 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Long-term Debt – Nonaffiliated | | | 640,770 | | | | 17,376 | |
Change in Advances from Affiliates, Net | | | (128,331 | ) | | | 117,879 | |
Retirement of Long-term Debt – Nonaffiliated | | | (229,655 | ) | | | (5 | ) |
Retirement of Long-term Debt – Affiliated | | | - | | | | (100,000 | ) |
Retirement of Cumulative Preferred Stock | | | (8 | ) | | | (4 | ) |
Principal Payments for Capital Lease Obligations | | | (1,876 | ) | | | (1,790 | ) |
Dividends Paid on Common Stock | | | (37,500 | ) | | | (44,000 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (200 | ) | | | (200 | ) |
Other Financing Activities | | | 14 | | | | 436 | |
Net Cash Flows from (Used for) Financing Activities | | | 243,214 | | | | (10,308 | ) |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 1,433 | | | | 236 | |
Cash and Cash Equivalents at Beginning of Period | | | 951 | | | | 2,006 | |
Cash and Cash Equivalents at End of Period | | $ | 2,384 | | | $ | 2,242 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 36,992 | | | $ | 38,971 | |
Net Cash Paid for Income Taxes | | | 629 | | | | - | |
Noncash Acquisitions Under Capital Leases | | | 368 | | | | 20,369 | |
Government Grants Included in Accounts Receivable at March 31, | | | 572 | | | | - | |
Construction Expenditures Included in Current Liabilities at March 31, | | | 38,071 | | | | 43,262 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
APPALACHIAN POWER COMPANY CONSOLIDATEDAND SUBSIDIARIES
INDEX OF 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. The footnotes begin on page 143.
| Footnote Reference |
| |
Significant Accounting Matters | Note 1 |
| |
Rate Matters | Note 2 |
| |
Commitments, Guarantees and Contingencies | Note 3 |
| |
Benefit Plans | Note 5 |
| |
Business Segments | Note 6 |
| |
Derivatives and Hedging | Note 7 |
| |
Fair Value Measurements | Note 8 |
| |
Income Taxes | Note 9 |
| |
Financing Activities | Note 10 |
| |
Cost Reduction Initiatives | Note 11 |
COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES
OHIO POWER COMPANY CONSOLIDATED | |
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS | |
| | | |
RESULTS OF OPERATIONS | | | |
| | | |
Third Quarter of 2010 Compared to Third Quarter of 2009 | |
| | | |
Reconciliation of Third Quarter of 2009 to Third Quarter of 2010 | |
Net Income | |
(in millions) | |
| | | |
Third Quarter of 2009 | | $ | 97 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins | | | 8 | |
Off-system Sales | | | 19 | |
Transmission Revenues | | | 1 | |
Other Revenues | | | (1 | ) |
Total Change in Gross Margin | | | 27 | |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | (17 | ) |
Depreciation and Amortization | | | (2 | ) |
Taxes Other Than Income Taxes | | | (4 | ) |
Carrying Costs Income | | | 3 | |
Interest Expense | | | 2 | |
Total Expenses and Other | | | (18 | ) |
| | | | |
Income Tax Expense | | | (5 | ) |
| | | | |
Third Quarter of 2010 | | $ | 101 | |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIESMANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS
EXECUTIVE OVERVIEW
Ohio Customer Choice
In CSPCo’s service territory, various competitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service. Through March 31, 2011, approximately 7,500 CSPCo retail customers have switched from CSPCo to alternative CRES providers. As a result, in comparison to the first three months of 2010, CSPCo lost approximately $18 million of generation related gross margin through March 31, 2011. Management anticipates recovery of a portion of this lost margin through off-system sales, including PJM capacity revenues.
Regulatory Activity
2009 – 2011 ESPs
In April 2011, the Supreme Court of Ohio issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged which resulted in three reversals, only two of which may have a prospective impact. If any rate changes result from the PUCO’s remand proceedings, such rate changes would be prospective from the date of the remand order through the remaining months of 2011. See “Ohio Electric Security Plan Filings” section of Note 2.
January 2012 – May 2014 ESP
In January 2011, CSPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing for generation. The rates would be effective with the first billing cycle of January 2012 through the last billing cycle of May 2014. The SSO presents redesigned generation rates by customer class. Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013. Under the new ESP, management estimates CSPCo will have base generation increases, excluding riders, of $17 million for 2012 and $46 million for 2013. The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESP could impact the outcome of the January 2012 – May 2014 ESP, though the nature and extent of that impact is not presently known. See “Ohio Electric Security Plan Filings” section of Note 2.
Ohio Distribution Base Rate Case
In February 2011, CSPCo filed with the PUCO for an annual increase in distribution rates of $34 million. The requested increase is based upon an 11.15% return on common equity to be effective January 2012. In addition to the annual increase, CSPCo requested recovery of the projected December 31, 2012 balance of certain distribution regulatory assets of $216 million, including approximately $102 million of unrecognized equity carrying costs. These assets would be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013. The actual balance of these distribution regulatory assets as of March 31, 2011 was $98 million, excluding $57 million of unrecognized equity carrying costs. If CSPCo is not ultimately permitted to fully recover its deferrals, it would reduce future net income and cash flows and impact financial condition. See “Ohio Distribution Base Rate Case” section of Note 2.
Proposed CSPCo and OPCo Merger
In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo. Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company. In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo. CSPCo and OPCo requested the reorganization transaction be effective in October 2011. Decisions are pending from the PUCO and the FERC. See “Proposed CSPCo and OPCo Merger” section of Note 2.
Litigation and Environmental Issues
In the ordinary course of business, CSPCo 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 resolution will be or the timing and amount of any loss, fine or penalty may be. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss 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 2010 Annual Report. Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 143. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.
See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 201 for additional discussion of relevant factors.
RESULTS OF OPERATIONS | | | | | |
| | | | | | |
KWH Sales/Degree Days | | | | | |
| | | | | | |
Summary of KWH Energy Sales |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in millions of KWH) |
Retail: | | | | | |
| Residential | | 2,127 | | | 2,226 |
| Commercial | | 1,995 | | | 2,002 |
| Industrial | | 1,270 | | | 1,111 |
| Miscellaneous | | 14 | | | 13 |
Total Retail | | 5,406 | | | 5,352 |
| | | | | |
Wholesale | | 863 | | | 719 |
| | | | | |
Total KWHs | | 6,269 | | | 6,071 |
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.
Summary of Heating and Cooling Degree Days |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in degree days) |
| | | | | | |
Actual - Heating (a) | | 1,928 | | | 1,965 |
Normal - Heating (b) | | 1,784 | | | 1,784 |
| | | | | | |
Actual - Cooling (c) | | 1 | | | - |
Normal - Cooling (b) | | 3 | | | 3 |
| | | | | | |
(a) | Eastern 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 cooling degree days are calculated on a 65 degree temperature base. |
First Quarter of 2011 Compared to First Quarter of 2010 | |
| | | |
Reconciliation of First Quarter of 2010 to First Quarter of 2011 | |
Net Income | |
(in millions) | |
| | | |
First Quarter of 2010 | | $ | 52 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins | | | 10 | |
Off-system Sales | | | 12 | |
Total Change in Gross Margin | | | 22 | |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | 1 | |
Depreciation and Amortization | | | (4 | ) |
Taxes Other Than Income Taxes | | | (3 | ) |
Interest Expense | | | 2 | |
Other Income | | | 1 | |
Total Expenses and Other | | | (3 | ) |
| | | | |
Income Tax Expense | | | (6 | ) |
| | | | |
First Quarter of 2011 | | $ | 65 | |
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 $8$10 million primarily due to the following: |
| | · | A $31 million increase in retail sales as a result of an increase in weather-related usage of residential and commercial customers primarily due to a 98% increase in cooling degree days and increased usage of industrial customers resulting from an improvement in demand. |
| | · | A $14$12 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Ohio Energy Efficiency & Peak Demand Response Program Rider.Reduction (EE/PDR) Programs. This increase in retail marginsRetail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below. |
| · | A $10 million increase associated with the final 2009 SEET order. |
| · | A $4 million increase in revenues due to the implementation of PUCO approved rider rates in September 2010 related to the Environmental Investment Carrying Cost Rider. |
| These increases were partially offset by: |
| | · | A $30An $18 million decrease in fuel recovery primarily dueattributable to favorable adjustments recorded in September 2009 relatedcustomers switching to deferred fuel.alternative competitive retail electric service (CRES) providers. |
| | · | A $6 million decrease as a result of the timing of approval and implementation of rates set by the Ohio ESP from April through December 2009. |
| · | Margins from Off-system Sales increased $19$12 million primarily due to increased pricesan increase in PJM capacity revenues, partially offset by lower trading and higher physical sales volumes.marketing margins. |
Total Expenses and Other and Income Tax Expense changed between years as follows:
| · | Other Operation and Maintenance expenses increased $17decreased $1 million primarily due to: |
| · | A $7 million decrease in transmission expense primarily due to the Transmission Agreement modification effective November 2010, a $14portion of which is included in the Ohio Transmission Cost Recovery Rider. |
| · | A $3 million decrease in employee-related expenses. |
| These decreases were partially offset by: |
| · | A $12 million increase in expenses due to the implementation of PUCO approved Ohio Energy Efficiency & Demand Response Program.EE/PDR programs. This increase in operationOther Operation and maintenanceMaintenance expense was offset by a corresponding increase in Retail Margins as discussed above. |
· | Depreciation and Amortization expenses increased $4 million as a result of recognizing the deferred debt and equity carrying charges on deferred fuel as permitted under the final 2009 SEET order. |
· | Taxes Other Than Income Taxes increased $3 million due to an increase in property taxes. |
| · | Income Tax Expense increased $5$6 million primarily due to an increase in pretaxpre-tax book income, andoffset in part by the regulatory accounting2010 tax treatment associated with the future reimbursement of state income taxes.Medicare Part D retiree prescription drug benefits. |
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.
See the “Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 201 for a discussion of accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See “Quantitative And Qualitative Disclosures About Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 201 for a discussion of market risk.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF INCOME | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| | | | | | |
| | 2011 | | | 2010 | |
REVENUES | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 503,371 | | | $ | 501,019 | |
Sales to AEP Affiliates | | | 40,725 | | | | 15,832 | |
Other Revenues | | | 506 | | | | 588 | |
TOTAL REVENUES | | | 544,602 | | | | 517,439 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 112,913 | | | | 114,441 | |
Purchased Electricity for Resale | | | 23,517 | | | | 19,645 | |
Purchased Electricity from AEP Affiliates | | | 101,611 | | | | 98,799 | |
Other Operation | | | 71,067 | | | | 77,326 | |
Maintenance | | | 29,100 | | | | 24,283 | |
Depreciation and Amortization | | | 41,426 | | | | 37,487 | |
Taxes Other Than Income Taxes | | | 50,149 | | | | 47,057 | |
TOTAL EXPENSES | | | 429,783 | | | | 419,038 | |
| | | | | | | | |
OPERATING INCOME | | | 114,819 | | | | 98,401 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest Income | | | 167 | | | | 142 | |
Carrying Costs Income | | | 3,654 | | | | 2,221 | |
Allowance for Equity Funds Used During Construction | | | 771 | | | | 921 | |
Interest Expense | | | (19,748 | ) | | | (21,784 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 99,663 | | | | 79,901 | |
| | | | | | | | |
Income Tax Expense | | | 34,105 | | | | 28,251 | |
| | | | | | | | |
NET INCOME | | | 65,558 | | | | 51,650 | |
| | | | | | | | |
Capital Stock Expense | | | 25 | | | | 39 | |
| | | | | | | | |
EARNINGS ATTRIBUTABLE TO COMMON STOCK | | $ | 65,533 | | | $ | 51,611 | |
| | | | | | | | |
The common stock of CSPCo is wholly-owned by AEP. | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S | |
EQUITY AND COMPREHENSIVE INCOME (LOSS) | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | | | | | | | | | | Accumulated | | | | |
| | | | | | | | | | | Other | | | | |
| | Common | | | Paid-in | | | Retained | | | Comprehensive | | | | |
| | Stock | | | Capital | | | Earnings | | | Income (Loss) | | | Total | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2009 | | $ | 41,026 | | | $ | 580,663 | | | $ | 788,139 | | | $ | (49,993 | ) | | $ | 1,359,835 | |
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (31,250 | ) | | | | | | | (31,250 | ) |
Capital Stock Expense | | | | | | | 39 | | | | (39 | ) | | | | | | | - | |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 1,328,585 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of | | | | | | | | | | | | | | | | | | | | |
Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $555 | | | | | | | | | | | | | | | (1,031 | ) | | | (1,031 | ) |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $333 | | | | | | | | | | | | | | | 619 | | | | 619 | |
NET INCOME | | | | | | | | | | | 51,650 | | | | | | | | 51,650 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 51,238 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – MARCH 31, 2010 | | $ | 41,026 | | | $ | 580,702 | | | $ | 808,500 | | | $ | (50,405 | ) | | $ | 1,379,823 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2010 | | $ | 41,026 | | | $ | 580,812 | | | $ | 915,713 | | | $ | (51,336 | ) | | $ | 1,486,215 | |
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (62,500 | ) | | | | | | | (62,500 | ) |
Capital Stock Expense | | | | | | | 25 | | | | (25 | ) | | | | | | | - | |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 1,423,715 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $114 | | | | | | | | | | | | | | | 213 | | | | 213 | |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $344 | | | | | | | | | | | | | | | 639 | | | | 639 | |
NET INCOME | | | | | | | | | | | 65,558 | | | | | | | | 65,558 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 66,410 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – MARCH 31, 2011 | | $ | 41,026 | | | $ | 580,837 | | | $ | 918,746 | | | $ | (50,484 | ) | | $ | 1,490,125 | |
| | | | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
ASSETS | |
March 31, 2011 and December 31, 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 1,385 | | | $ | 509 | |
Other Cash Deposits | | | 2,260 | | | | 2,260 | |
Advances to Affiliates | | | 63,706 | | | | 54,202 | |
Accounts Receivable: | | | | | | | | |
Customers | | | 50,017 | | | | 50,187 | |
Affiliated Companies | | | 44,261 | | | | 66,788 | |
Accrued Unbilled Revenues | | | 14,205 | | | | 32,821 | |
Miscellaneous | | | 4,715 | | | | 14,374 | |
Allowance for Uncollectible Accounts | | | (1,618 | ) | | | (1,584 | ) |
Total Accounts Receivable | | | 111,580 | | | | 162,586 | |
Fuel | | | 64,555 | | | | 72,882 | |
Materials and Supplies | | | 41,290 | | | | 42,033 | |
Emission Allowances | | | 26,461 | | | | 28,486 | |
Risk Management Assets | | | 22,221 | | | | 23,774 | |
Accrued Tax Benefits | | | 1,453 | | | | 8,797 | |
Regulatory Asset for Under-Recovered Fuel Costs | | | 19,199 | | | | - | |
Margin Deposits | | | 11,162 | | | | 14,762 | |
Prepayments and Other Current Assets | | | 11,066 | | | | 26,864 | |
TOTAL CURRENT ASSETS | | | 376,338 | | | | 437,155 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Generation | | | 2,719,642 | | | | 2,686,294 | |
Transmission | | | 676,250 | | | | 662,312 | |
Distribution | | | 1,804,501 | | | | 1,796,023 | |
Other Property, Plant and Equipment | | | 203,744 | | | | 203,593 | |
Construction Work in Progress | | | 142,609 | | | | 172,793 | |
Total Property, Plant and Equipment | | | 5,546,746 | | | | 5,521,015 | |
Accumulated Depreciation and Amortization | | | 1,959,482 | | | | 1,927,112 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 3,587,264 | | | | 3,593,903 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 303,741 | | | | 298,111 | |
Long-term Risk Management Assets | | | 23,080 | | | | 22,089 | |
Deferred Charges and Other Noncurrent Assets | | | 125,746 | | | | 152,932 | |
TOTAL OTHER NONCURRENT ASSETS | | | 452,567 | | | | 473,132 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 4,416,169 | | | $ | 4,504,190 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
| | | | | | | | |
| | | | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
LIABILITIES AND SHAREHOLDER'S EQUITY | |
March 31, 2011 and December 31, 2010 | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
| | (in thousands) | |
CURRENT LIABILITIES | | | | | | |
Accounts Payable: | | | | | | |
General | | $ | 80,031 | | | $ | 98,925 | |
Affiliated Companies | | | 55,640 | | | | 78,617 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 150,000 | | | | - | |
Risk Management Liabilities | | | 13,053 | | | | 15,967 | |
Customer Deposits | | | 30,222 | | | | 29,441 | |
Accrued Taxes | | | 175,816 | | | | 226,572 | |
Accrued Interest | | | 25,189 | | | | 22,533 | |
Other Current Liabilities | | | 93,112 | | | | 111,868 | |
TOTAL CURRENT LIABILITIES | | | 623,063 | | | | 583,923 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 1,288,900 | | | | 1,438,830 | |
Long-term Risk Management Liabilities | | | 7,653 | | | | 6,223 | |
Deferred Income Taxes | | | 619,951 | | | | 604,828 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 164,212 | | | | 163,888 | |
Employee Benefits and Pension Obligations | | | 135,202 | | | | 136,643 | |
Deferred Credits and Other Noncurrent Liabilities | | | 87,063 | | | | 83,640 | |
TOTAL NONCURRENT LIABILITIES | | | 2,302,981 | | | | 2,434,052 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 2,926,044 | | | | 3,017,975 | |
| | | | | | | | |
Rate Matters (Note 2) | | | | | | | | |
Commitments and Contingencies (Note 3) | | | | | | | | |
| | | | | | | | |
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 | | | 580,837 | | | | 580,812 | |
Retained Earnings | | | 918,746 | | | | 915,713 | |
Accumulated Other Comprehensive Income (Loss) | | | (50,484 | ) | | | (51,336 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | | 1,490,125 | | | | 1,486,215 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY | | $ | 4,416,169 | | | $ | 4,504,190 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 65,558 | | | $ | 51,650 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 41,426 | | | | 37,487 | |
Deferred Income Taxes | | | 31,902 | | | | 8,327 | |
Allowance for Equity Funds Used During Construction | | | (771 | ) | | | (921 | ) |
Mark-to-Market of Risk Management Contracts | | | (669 | ) | | | (11,609 | ) |
Property Taxes | | | 27,283 | | | | 24,131 | |
Fuel Over/Under-Recovery, Net | | | (4,891 | ) | | | 26,139 | |
Change in Other Noncurrent Assets | | | (9,041 | ) | | | (4,994 | ) |
Change in Other Noncurrent Liabilities | | | 5,100 | | | | (46 | ) |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 43,606 | | | | 5,553 | |
Fuel, Materials and Supplies | | | 10,033 | | | | (9,795 | ) |
Accounts Payable | | | (35,549 | ) | | | (22,402 | ) |
Accrued Taxes, Net | | | (48,059 | ) | | | (24,444 | ) |
Other Current Assets | | | 4,645 | | | | (428 | ) |
Other Current Liabilities | | | (25,526 | ) | | | (1,619 | ) |
Net Cash Flows from Operating Activities | | | 105,047 | | | | 77,029 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (45,732 | ) | | | (42,906 | ) |
Change in Other Cash Deposits | | | - | | | | 10,290 | |
Change in Advances to Affiliates, Net | | | (9,504 | ) | | | (37,818 | ) |
Acquisitions of Assets | | | (201 | ) | | | (190 | ) |
Proceeds from Sales of Assets | | | 2,439 | | | | 789 | |
Other Investing Activities | | | 12,179 | | | | - | |
Net Cash Flows Used for Investing Activities | | | (40,819 | ) | | | (69,835 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Long-term Debt – Nonaffiliated | | | - | | | | 149,625 | |
Change in Advances from Affiliates, Net | | | - | | | | (24,202 | ) |
Retirement of Long-term Debt – Affiliated | | | - | | | | (100,000 | ) |
Principal Payments for Capital Lease Obligations | | | (852 | ) | | | (1,120 | ) |
Dividends Paid on Common Stock | | | (62,500 | ) | | | (31,250 | ) |
Other Financing Activities | | | - | | | | 71 | |
Net Cash Flows Used for Financing Activities | | | (63,352 | ) | | | (6,876 | ) |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 876 | | | | 318 | |
Cash and Cash Equivalents at Beginning of Period | | | 509 | | | | 1,096 | |
Cash and Cash Equivalents at End of Period | | $ | 1,385 | | | $ | 1,414 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 16,396 | | | $ | 18,631 | |
Net Cash Paid for Income Taxes | | | 518 | | | | - | |
Noncash Acquisitions Under Capital Leases | | | 139 | | | | 8,353 | |
Government Grants Included in Accounts Receivable at March 31, | | | 1,938 | | | | - | |
Construction Expenditures Included in Current Liabilities at March 31, | | | 8,572 | | | | 13,891 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
INDEX OF 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. The footnotes begin on page 143.
| Footnote Reference |
| |
Significant Accounting Matters | Note 1 |
| |
Rate Matters | Note 2 |
| |
Commitments, Guarantees and Contingencies | Note 3 |
| |
Benefit Plans | Note 5 |
| |
Business Segments | Note 6 |
| |
Derivatives and Hedging | Note 7 |
| |
Fair Value Measurements | Note 8 |
| |
Income Taxes | Note 9 |
| |
Financing Activities | Note 10 |
| |
Cost Reduction Initiatives | Note 11 |
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS
EXECUTIVE OVERVIEW
Regulatory Activity
Cook Plant Unit 1 Fire and Shutdown
In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator. Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $395 million. Management believes that I&M should recover a significant portion of repair and replacement costs through the turbine vendor’s warranty, insurance and the regulatory process. I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power. The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors. As a result, the replacement of the repaired turbine rotors and other equipment is scheduled for the Unit 1 planned outage in the fall of 2011. If the ultimate costs of the incident are not covered by warranty, insurance or through the related regulatory process or if any future regulatory proceedings are adverse, it could reduce future net income and cash flows and impact financial condition. See “Michigan 2009 and 2010 Power Supply Cost Recovery Reconciliations” section of Note 2 and “Cook Plant Unit 1 Fire and Shutdown” section of Note 3.
As a result of the nuclear plant situation in Japan following an earthquake, management expects the Nuclear Regulatory Commission and possibly Congress to review safety procedures and requirements for nuclear generating facilities. This review could increase procedures and testing requirements and increase future operating costs at the Cook Plant.
Litigation and Environmental Issues
In the ordinary course of business, I&M 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 resolution will be or the timing and amount of any loss, fine or penalty may be. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss 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 2010 Annual Report. Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 143. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.
See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 201 for additional discussion of relevant factors.
Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009 |
RESULTS OF OPERATIONS | | | | |
Reconciliation of Nine Months Ended September 30, 2009 to Nine Months Ended September 30, 2010 |
Net Income |
(in millions) |
| | | | |
Nine Months Ended September 30, 2009 | | $ | 233 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail MarginsKWH Sales/Degree Days | | | 76 | |
Off-system Sales | | | 18 | |
Transmission Revenues | | | (1) | |
Other Revenues | | | (20) | |
Total Change in Gross Margin | | | 73 | |
| | | | |
| | | | | | |
Summary of KWH Energy Sales |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in millions of KWH) |
Retail: | | | | | |
| Residential | | 1,836 | | | 1,765 |
| Commercial | | 1,263 | | | 1,208 |
| Industrial | | 1,844 | | | 1,800 |
| Miscellaneous | | 23 | | | 18 |
Total Retail | | 4,966 | | | 4,791 |
| | | | | |
Wholesale | | 2,096 | | | 1,906 |
| | | | | |
Total KWHs | | 7,062 | | | 6,697 |
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.
Summary of Heating and Cooling Degree Days |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in degree days) |
| | | | | | |
Actual - Heating (a) | | 2,392 | | | 2,174 |
Normal - Heating (b) | | 2,175 | | | 2,172 |
| | | | | | |
Actual - Cooling (c) | | - | | | - |
Normal - Cooling (b) | | 1 | | | 1 |
| | | | | | |
(a) | Eastern 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 cooling degree days are calculated on a 65 degree temperature base. |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | (58) | |
Depreciation and Amortization | | | (8) | |
Taxes Other Than Income Taxes | | | (11) | |
Carrying Costs Income | | | 10 | |
Other Income | | | 1 | |
Interest Expense | | | (4) | |
Total Expenses and Other | | | (70) | |
| | | | |
Income Tax Expense | | | (6) | |
| | | | |
Nine Months Ended September 30,First Quarter of 2011 Compared to First Quarter of 2010 | | $ | 230 | |
| | | |
Reconciliation of First Quarter of 2010 to First Quarter of 2011 | |
Net Income | |
(in millions) | |
| | | |
First Quarter of 2010 | | $ | 45 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins | | | 13 | |
FERC Municipals and Cooperatives | | | 2 | |
Off-system Sales | | | 2 | |
Other Revenues | | | (2 | ) |
Total Change in Gross Margin | | | 15 | |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | (6 | ) |
Taxes Other Than Income Taxes | | | (1 | ) |
Other Income | | | (1 | ) |
Interest Expense | | | 1 | |
Total Expenses and Other | | | (7 | ) |
| | | | |
Income Tax Expense | | | (8 | ) |
| | | | |
First Quarter of 2011 | | $ | 45 | |
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 $76$13 million primarily due to the following: |
| | · | A $44An $8 million increase in capacity settlements under the Interconnection Agreement. |
| | · | A $29 million increase in retail sales primarily a result of an increase in weather-related usage of residential customers primarily due to an 82% increaseMichigan rate settlement effective in cooling degree days and increased usage of industrial customers resulting from an improvement in demand. |
| | · | A $19 million increase in demand charges from WPCo effective JanuaryDecember 2010. |
| | · | An $18 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Ohio Energy Efficiency & Demand Response Program Rider. This increase in retail margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below. |
| | These increases were partially offset by: |
| | · | A $10 million decrease in fuel recovery related to coal pile survey adjustments recorded in 2009 for the 2008 consumption portion. The 2008 portion was excluded from the deferred fuel calculation. The PUCO’s March 2009 approval of OPCo’s ESP allowed for the recovery of fuel and related costs beginning January 1, 2009. |
| | · | A $7 million decrease related to increased consumable and allowance expenses. |
| · | Marginsincrease in margins from Off-system Sales increased $18 millionresidential sales primarily due to increased prices and higher physical sales volumes, partially offset by lower trading and marketing margins.
|
| · | Other Revenues decreased $20 million primarily due to reduced gains on sales of emission allowances which are partially offset by sharing in the fuel clause. usage reflecting favorable weather. |
Total Expenses and Other and Income Tax Expense changed between years as follows:
| · | Other Operation and Maintenance expenses increased $58$6 million primarily due to: |
| | · | A $53 million increase due to expenses related to the cost reduction initiatives. |
| | · | An $18 million increase in expenses due to the implementation of PUCO approved Ohio Energy Efficiency & Demand Response Program. This increase in operation and maintenance expense was offset by a corresponding increase in Retail Margins as discussed above. |
| | · | An $8 million increase in recoverable customer account expenses due to increased Universal Service Fund surcharge rates for customers who qualify for payment assistance. |
| | These increases were partially offset by: |
| | · | A $7 million decrease related to a 2009 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.following: |
| · | Depreciation and Amortization increased $8A $10 million increase in transmission expense primarily due to: to the Transmission Agreement modification effective November 2010. |
| | · | A $12 million increase from higher depreciable property balances as a result of environmental improvements placed in service and various other property additions. |
| | This increase was partially offset by: |
| | · | A $4$5 million decrease due to the completion of the amortization of softwarein administrative and leasehold improvements in the fourth quarter of 2009.general expenses. |
| · | Taxes Other Than Income Taxes increased $11 million primarily due to a $6 million increase in real and property taxes, a $3 million increase in state excise taxes as well as a $2 million increase due to the employer portion of payroll taxes incurred related to the cost reduction initiatives.
|
| · | Carrying Costs Income increased $10 million primarily due to higher Ohio ESP FAC carrying charges in 2010 related to an increase in the deferred fuel regulatory asset balance.
|
| · | Income Tax Expense increased $6$8 million primarily due to an increase in pretax book income and thefederal income tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits.adjustments related to prior year tax returns. |
FINANCIAL CONDITIONCRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
LIQUIDITY
OPCo participates inSee the Utility Money Pool, which provides access to AEP’s liquidity. OPCo relies upon ready access to capital markets, cash flows from operations“Critical Accounting Policies and access to the Utility Money Pool to fund current operations and capital expenditures. See theEstimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.
See the “Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 144201 for additionala discussion of liquidity.accounting pronouncements.
Credit RatingsQUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Downgrades in credit ratings by oneSee “Quantitative And Qualitative Disclosures About Market Risk” section of the rating agencies could increase OPCo’s borrowing costs.“Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 201 for a discussion of market risk.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF INCOME | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| | | | | | |
| | 2011 | | | 2010 | |
REVENUES | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 456,862 | | | $ | 438,024 | |
Sales to AEP Affiliates | | | 74,868 | | | | 84,217 | |
Other Revenues - Affiliated | | | 24,331 | | | | 27,966 | |
Other Revenues - Nonaffiliated | | | 4,431 | | | | 2,849 | |
TOTAL REVENUES | | | 560,492 | | | | 553,056 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 115,062 | | | | 119,181 | |
Purchased Electricity for Resale | | | 29,292 | | | | 29,767 | |
Purchased Electricity from AEP Affiliates | | | 79,584 | | | | 82,250 | |
Other Operation | | | 133,211 | | | | 130,681 | |
Maintenance | | | 51,000 | | | | 48,444 | |
Depreciation and Amortization | | | 34,087 | | | | 33,831 | |
Taxes Other Than Income Taxes | | | 22,262 | | | | 21,032 | |
TOTAL EXPENSES | | | 464,498 | | | | 465,186 | |
| | | | | | | | |
OPERATING INCOME | | | 95,994 | | | | 87,870 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest Income | | | 696 | | | | 485 | |
Allowance for Equity Funds Used During Construction | | | 3,199 | | | | 4,435 | |
Interest Expense | | | (25,191 | ) | | | (26,101 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 74,698 | | | | 66,689 | |
| | | | | | | | |
Income Tax Expense | | | 29,271 | | | | 21,631 | |
| | | | | | | | |
NET INCOME | | | 45,427 | | | | 45,058 | |
| | | | | | | | |
Preferred Stock Dividend Requirements | | | 85 | | | | 85 | |
| | | | | | | | |
EARNINGS ATTRIBUTABLE TO COMMON STOCK | | $ | 45,342 | | | $ | 44,973 | |
| | | | | | | | |
The common stock of I&M is wholly-owned by AEP. | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
CASH FLOWINDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S | |
EQUITY AND COMPREHENSIVE INCOME (LOSS) | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | | | | | | | | | | Accumulated | | | | |
| | | | | | | | | | | Other | | | | |
| | Common | | | Paid-in | | | Retained | | | Comprehensive | | | | |
| | Stock | | | Capital | | | Earnings | | | Income (Loss) | | | Total | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2009 | | $ | 56,584 | | | $ | 981,292 | | | $ | 656,608 | | | $ | (21,701 | ) | | $ | 1,672,783 | |
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (25,750 | ) | | | | | | | (25,750 | ) |
Preferred Stock Dividends | | | | | | | | | | | (85 | ) | | | | | | | (85 | ) |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 1,646,948 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of | | | | | | | | | | | | | | | | | | | | |
Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $422 | | | | | | | | | | | | | | | (784 | ) | | | (784 | ) |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $117 | | | | | | | | | | | | | | | 218 | | | | 218 | |
NET INCOME | | | | | | | | | | | 45,058 | | | | | | | | 45,058 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 44,492 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – MARCH 31, 2010 | | $ | 56,584 | | | $ | 981,292 | | | $ | 675,831 | | | $ | (22,267 | ) | | $ | 1,691,440 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2010 | | $ | 56,584 | | | $ | 981,294 | | | $ | 677,360 | | | $ | (20,889 | ) | | $ | 1,694,349 | |
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (18,750 | ) | | | | | | | (18,750 | ) |
Preferred Stock Dividends | | | | | | | | | | | (85 | ) | | | | | | | (85 | ) |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 1,675,514 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $286 | | | | | | | | | | | | | | | 531 | | | | 531 | |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $128 | | | | | | | | | | | | | | | 237 | | | | 237 | |
NET INCOME | | | | | | | | | | | 45,427 | | | | | | | | 45,427 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 46,195 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – MARCH 31, 2011 | | $ | 56,584 | | | $ | 981,294 | | | $ | 703,952 | | | $ | (20,121 | ) | | $ | 1,721,709 | |
| | | | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
Cash flows for the nine months ended September 30, 2010 and 2009 were as follows:INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
ASSETS | |
March 31, 2011 and December 31, 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 912 | | | $ | 361 | |
Advances to Affiliates | | | 56,813 | | | | - | |
Accounts Receivable: | | | | | | | | |
Customers | | | 56,396 | | | | 76,193 | |
Affiliated Companies | | | 62,023 | | | | 149,169 | |
Accrued Unbilled Revenues | | | 28,066 | | | | 19,449 | |
Miscellaneous | | | 11,714 | | | | 10,968 | |
Allowance for Uncollectible Accounts | | | (1,687 | ) | | | (1,692 | ) |
Total Accounts Receivable | | | 156,512 | | | | 254,087 | |
Fuel | | | 79,584 | | | | 87,551 | |
Materials and Supplies | | | 177,955 | | | | 178,331 | |
Risk Management Assets | | | 26,436 | | | | 27,526 | |
Accrued Tax Benefits | | | 68,504 | | | | 71,113 | |
Deferred Cook Plant Fire Costs | | | 46,532 | | | | 45,752 | |
Prepayments and Other Current Assets | | | 24,607 | | | | 33,713 | |
TOTAL CURRENT ASSETS | | | 637,855 | | | | 698,434 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Generation | | | 3,781,344 | | | | 3,774,262 | |
Transmission | | | 1,197,343 | | | | 1,188,665 | |
Distribution | | | 1,427,078 | | | | 1,411,095 | |
Other Property, Plant and Equipment (including nuclear fuel and coal mining) | | | 715,565 | | | | 719,708 | |
Construction Work in Progress | | | 301,781 | | | | 301,534 | |
Total Property, Plant and Equipment | | | 7,423,111 | | | | 7,395,264 | |
Accumulated Depreciation, Depletion and Amortization | | | 3,153,696 | | | | 3,124,998 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 4,269,415 | | | | 4,270,266 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 534,389 | | | | 556,254 | |
Spent Nuclear Fuel and Decommissioning Trusts | | | 1,558,535 | | | | 1,515,227 | |
Long-term Risk Management Assets | | | 31,923 | | | | 31,485 | |
Deferred Charges and Other Noncurrent Assets | | | 85,384 | | | | 77,229 | |
TOTAL OTHER NONCURRENT ASSETS | | | 2,210,231 | | | | 2,180,195 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 7,117,501 | | | $ | 7,148,895 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
| | | | | | | | |
| | | | | | | | |
| | 2010 | | | 2009 | |
| | (in thousands) | |
Cash and Cash Equivalents at Beginning of Period | | $ | 1,984 | | | $ | 12,679 | |
Net Cash Flows from Operating Activities | | | 627,472 | | | | 136,802 | |
Net Cash Flows Used for Investing Activities | | | (54,651 | ) | | | (674,647 | ) |
Net Cash Flows from (Used for) Financing Activities | | | (573,451 | ) | | | 528,116 | |
Net Decrease in Cash and Cash Equivalents | | | (630 | ) | | | (9,729 | ) |
Cash and Cash Equivalents at End of Period | | $ | 1,354 | | | $ | 2,950 | |
Operating Activities | | | | | | |
| | | | | | |
| | | | | | |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
LIABILITIES AND SHAREHOLDERS' EQUITY | |
March 31, 2011 and December 31, 2010 | |
(dollars in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
CURRENT LIABILITIES | | | | | | |
Advances from Affiliates | | $ | - | | | $ | 42,769 | |
Accounts Payable: | | | | | | | | |
General | | | 84,677 | | | | 121,665 | |
Affiliated Companies | | | 69,464 | | | | 105,221 | |
Long-term Debt Due Within One Year - Nonaffiliated | | | | | | | | |
(March 31, 2011 and December 31, 2010 amounts include $78,332 and $77,457, | | | | | | | | |
respectively, related to DCC Fuel) | | | 155,332 | | | | 154,457 | |
Risk Management Liabilities | | | 13,663 | | | | 16,785 | |
Customer Deposits | | | 29,240 | | | | 29,264 | |
Accrued Taxes | | | 78,574 | | | | 62,637 | |
Accrued Interest | | | 23,045 | | | | 27,444 | |
Other Current Liabilities | | | 142,392 | | | | 140,710 | |
TOTAL CURRENT LIABILITIES | | | 596,387 | | | | 700,952 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 1,843,771 | | | | 1,849,769 | |
Long-term Risk Management Liabilities | | | 7,992 | | | | 6,530 | |
Deferred Income Taxes | | | 780,312 | | | | 760,105 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 866,458 | | | | 852,197 | |
Asset Retirement Obligations | | | 974,935 | | | | 963,029 | |
Deferred Credits and Other Noncurrent Liabilities | | | 317,865 | | | | 313,892 | |
TOTAL NONCURRENT LIABILITIES | | | 4,791,333 | | | | 4,745,522 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 5,387,720 | | | | 5,446,474 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 8,072 | | | | 8,072 | |
| | | | | | | | |
Rate Matters (Note 2) | | | | | | | | |
Commitments and Contingencies (Note 3) | | | | | | | | |
| | | | | | | | |
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 | | | 981,294 | | | | 981,294 | |
Retained Earnings | | | 703,952 | | | | 677,360 | |
Accumulated Other Comprehensive Income (Loss) | | | (20,121 | ) | | | (20,889 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | | 1,721,709 | | | | 1,694,349 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 7,117,501 | | | $ | 7,148,895 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 45,427 | | | $ | 45,058 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 34,087 | | | | 33,831 | |
Deferred Income Taxes | | | 25,087 | | | | 18,442 | |
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net | | | 11,616 | | | | (20,025 | ) |
Allowance for Equity Funds Used During Construction | | | (3,199 | ) | | | (4,435 | ) |
Mark-to-Market of Risk Management Contracts | | | (658 | ) | | | (20,345 | ) |
Amortization of Nuclear Fuel | | | 34,240 | | | | 30,090 | |
Fuel Over/Under Recovery, Net | | | 4,156 | | | | 16,439 | |
Change in Other Noncurrent Assets | | | (6,066 | ) | | | (11,056 | ) |
Change in Other Noncurrent Liabilities | | | 13,327 | | | | 28,926 | |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 97,575 | | | | 28,078 | |
Fuel, Materials and Supplies | | | 8,343 | | | | (18,972 | ) |
Accounts Payable | | | (71,206 | ) | | | 13,171 | |
Accrued Taxes, Net | | | 14,479 | | | | 23,964 | |
Other Current Assets | | | (1,475 | ) | | | (13,044 | ) |
Other Current Liabilities | | | 3,865 | | | | 38,068 | |
Net Cash Flows from Operating Activities | | | 209,598 | | | | 188,190 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (54,733 | ) | | | (104,796 | ) |
Change in Advances to Affiliates, Net | | | (56,813 | ) | | | 28,826 | |
Purchases of Investment Securities | | | (305,945 | ) | | | (247,632 | ) |
Sales of Investment Securities | | | 287,761 | | | | 232,078 | |
Acquisitions of Nuclear Fuel | | | (27,132 | ) | | | (37,616 | ) |
Other Investing Activities | | | 17,029 | | | | 500 | |
Net Cash Flows Used for Investing Activities | | | (139,833 | ) | | | (128,640 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Long-term Debt - Nonaffiliated | | | 76,864 | | | | - | |
Change in Advances from Affiliates, Net | | | (42,769 | ) | | | - | |
Retirement of Long-term Debt - Nonaffiliated | | | (82,354 | ) | | | - | |
Retirement of Long-term Debt - Affiliated | | | - | | | | (25,000 | ) |
Principal Payments for Capital Lease Obligations | | | (2,128 | ) | | | (8,524 | ) |
Dividends Paid on Common Stock | | | (18,750 | ) | | | (25,750 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (85 | ) | | | (85 | ) |
Other Financing Activities | | | 8 | | | | 24 | |
Net Cash Flows Used for Financing Activities | | | (69,214 | ) | | | (59,335 | ) |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 551 | | | | 215 | |
Cash and Cash Equivalents at Beginning of Period | | | 361 | | | | 779 | |
Cash and Cash Equivalents at End of Period | | $ | 912 | | | $ | 994 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 28,542 | | | $ | 30,056 | |
Net Cash Paid (Received) for Income Taxes | | | (1,033 | ) | | | - | |
Noncash Acquisitions Under Capital Leases | | | 693 | | | | 8,476 | |
Construction Expenditures Included in Current Liabilities at March 31, | | | 21,651 | | | | 29,496 | |
Acquisition of Nuclear Fuel Included in Current Liabilities at March 31, | | | 377 | | | | 2,705 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX OF CONDENSED NOTES TO CONDENSED FINANCIAL STATEMENTS OF
REGISTRANT SUBSIDIARIES
Net Cash Flows from Operating Activities were $627 million in 2010. OPCo produced Net Income of $230 million duringThe condensed notes to I&M’s condensed consolidated financial statements are combined with the period and noncash expense items of $270 millioncondensed notes to condensed financial statements for Depreciation and Amortization, $126 million for Deferred Income Taxes and $72 million for Property Taxes. OPCo also contributed $47 millionother registrant subsidiaries. Listed below are the notes that apply to the qualified pension trust.I&M. 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 number of items. Fuel, Materials and Supplies had a $75 million inflow primarily due to a decrease in coal inventory reflecting increased customer demand for electricity. Accounts Receivable, Net had a $57 million inflow primarily due to decreased sales to affiliates and settlement of allowance sales to affiliated companies. Account Payable had a $46 million outflow primarily due to timing differences of payments. The $37 million inflow from Accrued Taxes, Net includes a third quarter 2010 income tax refund of $138 million as a result of a federal net income tax operating loss in 2009 that was carried back to 2007 and 2008. Items contributing to the net income tax operating loss include bonus depreciation and the favorable impact of a change in tax accounting method related to units of property. The $116 million increase in Fuel Over/Under-Recovery, Net reflects the deferral of fuel costs as a fuel clause was reactivated in 2009 under OPCo’s ESP.footnotes begin on page 143.
Net Cash Flows from Operating Activities were $137 million in 2009. OPCo produced Net Income of $233 million during the period and noncash expense items of $263 million for Depreciation and Amortization, $213 million for Deferred Income Taxes and $67 million for Property 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 primarily relates to a number of items. Fuel, Materials and Supplies had a $181 million outflow primarily due to an increase in coal inventory reflecting decreased customer demand for electricity as a result of the economi c slowdown. Accounts Payable had a $139 million outflow primarily due to OPCo’s provision for revenue refund of $62 million which was paid in the first quarter of 2009 to the AEP West companies as part of the FERC’s order on the SIA. Accrued Taxes, Net had a $104 million outflow due to temporary timing differences of payments for property taxes and a decrease of federal income tax related accruals. The $242 million change in Fuel Over/Under-Recovery, Net reflects the deferral of fuel costs as a fuel clause was reactivated in 2009 under OPCo’s ESP. | Footnote Reference |
| |
Significant Accounting Matters | Note 1 |
| |
Rate Matters | Note 2 |
| |
Commitments, Guarantees and Contingencies | Note 3 |
| |
Benefit Plans | Note 5 |
| |
Business Segments | Note 6 |
| |
Derivatives and Hedging | Note 7 |
| |
Fair Value Measurements | Note 8 |
| |
Income Taxes | Note 9 |
| |
Financing Activities | Note 10 |
| |
Cost Reduction Initiatives | Note 11 |
Investing Activities
Net Cash Flows Used for Investing Activities were $55 million and $675 million in 2010 and 2009, respectively. Construction Expenditures of $208 million and $343 million in 2010 and 2009, respectively, primarily related to environmental upgrades, as well as projects to improve service reliability for transmission and distribution. Environmental upgrades include FGD projects at the Amos Plant. OPCo had a net decrease of $148 million and a net increase of $368 million in loans to the Utility Money Pool during 2010 and 2009, respectively.
Financing Activities
Net Cash Flows from Financing Activities were $243 million in 2011. APCo issued $350 million of Senior Unsecured Notes and $295 million of Pollution Control Bonds, partially offset by the retirement of $230 million of Pollution Control Bonds. APCo had a net decrease of $128 million in borrowings from the Utility Money Pool. In addition, APCo paid $38 million in common stock dividends.
Net Cash Flows Used for Financing Activities were $573$10 million in 2010. OPCo issued Pollution Control BondsAPCo had a net increase of $86$118 million $79 million and $39 million. OPCoin borrowings from the Utility Money Pool. APCo retired $400$100 million of Senior Unsecured Notes. OPCo retired $79 millionNotes Payable - Affiliated and $39issued $17.5 million of Pollution Control Bonds.Bonds in 2010. In addition, OPCoAPCo paid $247$44 million in common stock dividends.
In April 2011, APCo retired $250 million of dividends on common stock.
Net Cash Flows from Financing Activities were $528 million in 2009 primarily due to a $550 million Capital Contribution from Parent as well as a $500 million issuance of Senior Unsecured Notes. These increases were partially offset by a $218 million reacquisition of Pollution Control Bonds related to JMG and a $78 million retirement of Notes Payable – Nonaffiliated. OPCo also had a net decrease in borrowings of $134 million from the Utility Money Pool.
In November 2010, OPCo retired $200 million of 5.3%5.55% Senior Unsecured Notes due in 2010.2011.
Long-term debt issuances, retirements and retirementsprincipal payments made during the first ninethree months of 20102011 were:
Issuances | | | | | | | | |
| | | Principal | | Interest | | Due |
| Type of Debt | | Amount | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| Senior Unsecured Notes | | $ | 350,000 | | 4.60 | | 2021 |
| Pollution Control Bonds | | | 65,350 | | 2.00 | | 2012 |
| Pollution Control Bonds | | | 75,000 | (a) | Variable | | 2036 |
| Pollution Control Bonds | | | 50,275 | (a) | Variable | | 2036 |
| Pollution Control Bonds | | | 54,375 | (a) | Variable | | 2042 |
| Pollution Control Bonds | | | 50,000 | (a) | Variable | | 2042 |
Issuances | | | | | | | | |
| | | Principal | | Interest | | Due |
| Type of Debt | | Amount | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| Pollution Control Bonds | | $ | 86,000 | | 3.125 | | 2015 |
| Pollution Control Bonds | | | 79,450 | | 3.25 | | 2014 |
| Pollution Control Bonds | | | 39,130 | | 2.875 | | 2014 |
| (a) | These pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on APCo’s Condensed Consolidated Balance Sheets. |
Retirements | | | | | | | |
| | | Principal | | Interest | | Due |
| Type of Debt | | Amount Paid | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| Senior Unsecured Notes | | $ | 400,000 | | Variable | | 2010 |
| Pollution Control Bonds | | | 79,450 | | 7.125 | | 2010 |
| Pollution Control Bonds | | | 19,565 | | 5.625 | | 2022 |
| Pollution Control Bonds | | | 19,565 | | 5.625 | | 2023 |
Retirements and Principal Payments | | | | | | | |
| | | Principal | | Interest | | Due |
| Type of Debt | | Amount Paid | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| Pollution Control Bonds | | $ | 75,000 | | Variable | | 2036 |
| Pollution Control Bonds | | | 50,275 | | Variable | | 2036 |
| Pollution Control Bonds | | | 54,375 | | Variable | | 2042 |
| Pollution Control Bonds | | | 50,000 | | Variable | | 2042 |
| Land Note | | | 5 | | 13.718 | | 2026 |
SUMMARYCONTRACTUAL OBLIGATION INFORMATION
A summary of contractual obligations is included in the 20092010 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in the “Cash Flow” section above.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.
See the “Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 201 for a discussion of accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See “Quantitative And Qualitative Disclosures About Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 201 for a discussion of market risk.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF INCOME | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| | | | | | |
| | 2011 | | | 2010 | |
REVENUES | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 751,012 | | | $ | 845,990 | |
Sales to AEP Affiliates | | | 78,691 | | | | 78,771 | |
Other Revenues | | | 2,117 | | | | 1,862 | |
TOTAL REVENUES | | | 831,820 | | | | 926,623 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 180,581 | | | | 180,640 | |
Purchased Electricity for Resale | | | 69,218 | | | | 63,683 | |
Purchased Electricity from AEP Affiliates | | | 224,189 | | | | 267,502 | |
Other Operation | | | 113,276 | | | | 90,040 | |
Maintenance | | | 32,293 | | | | 63,110 | |
Depreciation and Amortization | | | 69,099 | | | | 77,430 | |
Taxes Other Than Income Taxes | | | 27,103 | | | | 26,280 | |
TOTAL EXPENSES | | | 715,759 | | | | 768,685 | |
| | | | | | | | |
OPERATING INCOME | | | 116,061 | | | | 157,938 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest Income | | | 320 | | | | 291 | |
Carrying Costs Income | | | 3,439 | | | | 5,764 | |
Allowance for Equity Funds Used During Construction | | | 883 | | | | 1,163 | |
Interest Expense | | | (52,939 | ) | | | (51,727 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 67,764 | | | | 113,429 | |
| | | | | | | | |
Income Tax Expense | | | 28,784 | | | | 43,147 | |
| | | | | | | | |
NET INCOME | | | 38,980 | | | | 70,282 | |
| | | | | | | | |
Preferred Stock Dividend Requirements Including Capital Stock Expense | | | 200 | | | | 225 | |
| | | | | | | | |
EARNINGS ATTRIBUTABLE TO COMMON STOCK | | $ | 38,780 | | | $ | 70,057 | |
| |
The common stock of APCo is wholly-owned by AEP. | |
| |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S | |
EQUITY AND COMPREHENSIVE INCOME (LOSS) | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | | | | | | | | | | Accumulated | | | | |
| | | | | | | | | | | Other | | | | |
| | Common | | | Paid-in | | | Retained | | | Comprehensive | | | | |
| | Stock | | | Capital | | | Earnings | | | Income (Loss) | | | Total | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2009 | | $ | 260,458 | | | $ | 1,475,393 | | | $ | 1,085,980 | | | $ | (50,254 | ) | | $ | 2,771,577 | |
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (44,000 | ) | | | | | | | (44,000 | ) |
Preferred Stock Dividends | | | | | | | | | | | (200 | ) | | | | | | | (200 | ) |
Capital Stock Expense | | | | | | | 27 | | | | (25 | ) | | | | | | | 2 | |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 2,727,379 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of | | | | | | | | | | | | | | | | | | | | |
Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $940 | | | | | | | | | | | | | | | (1,746 | ) | | | (1,746 | ) |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $562 | | | | | | | | | | | | | | | 1,043 | | | | 1,043 | |
NET INCOME | | | | | | | | | | | 70,282 | | | | | | | | 70,282 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 69,579 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – MARCH 31, 2010 | | $ | 260,458 | | | $ | 1,475,420 | | | $ | 1,112,037 | | | $ | (50,957 | ) | | $ | 2,796,958 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2010 | | $ | 260,458 | | | $ | 1,475,496 | | | $ | 1,133,748 | | | $ | (48,023 | ) | | $ | 2,821,679 | |
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (37,500 | ) | | | | | | | (37,500 | ) |
Preferred Stock Dividends | | | | | | | | | | | (200 | ) | | | | | | | (200 | ) |
Capital Stock Expense | | | | | | | 3 | | | | | | | | | | | | 3 | |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 2,783,982 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of | | | | | | | | | | | | | | | | | | | | |
Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $275 | | | | | | | | | | | | | | | 511 | | | | 511 | |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $418 | | | | | | | | | | | | | | | 777 | | | | 777 | |
NET INCOME | | | | | | | | | | | 38,980 | | | | | | | | 38,980 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 40,268 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – MARCH 31, 2011 | | $ | 260,458 | | | $ | 1,475,499 | | | $ | 1,135,028 | | | $ | (46,735 | ) | | $ | 2,824,250 | |
| |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
ASSETS | |
March 31, 2011 and December 31, 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 2,384 | | | $ | 951 | |
Advances to Affiliates | | | 383,537 | | | | - | |
Accounts Receivable: | | | | | | | | |
Customers | | | 153,002 | | | | 166,878 | |
Affiliated Companies | | | 101,346 | | | | 145,972 | |
Accrued Unbilled Revenues | | | 58,693 | | | | 108,210 | |
Miscellaneous | | | 1,348 | | | | 3,090 | |
Allowance for Uncollectible Accounts | | | (7,045 | ) | | | (6,667 | ) |
Total Accounts Receivable | | | 307,344 | | | | 417,483 | |
Fuel | | | 167,153 | | | | 230,697 | |
Materials and Supplies | | | 91,068 | | | | 89,370 | |
Risk Management Assets | | | 38,923 | | | | 53,242 | |
Accrued Tax Benefits | | | 109,294 | | | | 104,435 | |
Regulatory Asset for Under-Recovered Fuel Costs | | | 18,131 | | | | 18,300 | |
Prepayments and Other Current Assets | | | 29,707 | | | | 35,811 | |
TOTAL CURRENT ASSETS | | | 1,147,541 | | | | 950,289 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Generation | | | 5,096,419 | | | | 4,736,150 | |
Transmission | | | 1,874,320 | | | | 1,852,415 | |
Distribution | | | 2,760,683 | | | | 2,740,752 | |
Other Property, Plant and Equipment | | | 348,613 | | | | 348,013 | |
Construction Work in Progress | | | 209,978 | | | | 562,280 | |
Total Property, Plant and Equipment | | | 10,290,013 | | | | 10,239,610 | |
Accumulated Depreciation and Amortization | | | 2,882,681 | | | | 2,843,087 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 7,407,332 | | | | 7,396,523 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 1,485,103 | | | | 1,486,625 | |
Long-term Risk Management Assets | | | 40,266 | | | | 38,420 | |
Deferred Charges and Other Noncurrent Assets | | | 128,641 | | | | 125,296 | |
TOTAL OTHER NONCURRENT ASSETS | | | 1,654,010 | | | | 1,650,341 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 10,208,883 | | | $ | 9,997,153 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
LIABILITIES AND SHAREHOLDERS' EQUITY | |
March 31, 2011 and December 31, 2010 | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
| | (in thousands) | |
CURRENT LIABILITIES | | | | | | |
Advances from Affiliates | | $ | - | | | $ | 128,331 | |
Accounts Payable: | | | | | | | | |
General | | | 155,890 | | | | 223,144 | |
Affiliated Companies | | | 133,716 | | | | 166,884 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 479,673 | | | | 479,672 | |
Risk Management Liabilities | | | 22,746 | | | | 27,993 | |
Customer Deposits | | | 59,385 | | | | 58,451 | |
Deferred Income Taxes | | | 40,752 | | | | 44,180 | |
Accrued Taxes | | | 76,268 | | | | 75,619 | |
Accrued Interest | | | 71,566 | | | | 57,871 | |
Other Current Liabilities | | | 81,662 | | | | 93,286 | |
TOTAL CURRENT LIABILITIES | | | 1,121,658 | | | | 1,355,431 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 3,496,032 | | | | 3,081,469 | |
Long-term Risk Management Liabilities | | | 13,339 | | | | 10,873 | |
Deferred Income Taxes | | | 1,679,963 | | | | 1,642,072 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 554,577 | | | | 562,381 | |
Employee Benefits and Pension Obligations | | | 302,517 | | | | 306,460 | |
Deferred Credits and Other Noncurrent Liabilities | | | 198,811 | | | | 199,041 | |
TOTAL NONCURRENT LIABILITIES | | | 6,245,239 | | | | 5,802,296 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 7,366,897 | | | | 7,157,727 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 17,736 | | | | 17,747 | |
| | | | | | | | |
Rate Matters (Note 2) | | | | | | | | |
Commitments and Contingencies (Note 3) | | | | | | | | |
| | | | | | | | |
COMMON SHAREHOLDER’S EQUITY | | | | | | | | |
Common Stock – No Par Value: | | | | | | | | |
Authorized – 30,000,000 Shares | | | | | | | | |
Outstanding – 13,499,500 Shares | | | 260,458 | | | | 260,458 | |
Paid-in Capital | | | 1,475,499 | | | | 1,475,496 | |
Retained Earnings | | | 1,135,028 | | | | 1,133,748 | |
Accumulated Other Comprehensive Income (Loss) | | | (46,735 | ) | | | (48,023 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | | 2,824,250 | | | | 2,821,679 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 10,208,883 | | | $ | 9,997,153 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 38,980 | | | $ | 70,282 | |
Adjustments to Reconcile Net Income to Net Cash Flows from | | | | | | | | |
Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 69,099 | | | | 77,430 | |
Deferred Income Taxes | | | 60,802 | | | | 19,121 | |
Carrying Costs Income | | | (3,439 | ) | | | (5,764 | ) |
Allowance for Equity Funds Used During Construction | | | (883 | ) | | | (1,163 | ) |
Mark-to-Market of Risk Management Contracts | | | (1,553 | ) | | | (12,977 | ) |
Fuel Over/Under-Recovery, Net | | | (9,857 | ) | | | (11,804 | ) |
Change in Other Noncurrent Assets | | | 10,237 | | | | 11,082 | |
Change in Other Noncurrent Liabilities | | | 12,013 | | | | (2,568 | ) |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 109,662 | | | | 80,813 | |
Fuel, Materials and Supplies | | | 61,846 | | | | 41,054 | |
Accounts Payable | | | (71,056 | ) | | | (97,732 | ) |
Accrued Taxes, Net | | | (32,472 | ) | | | 24,150 | |
Other Current Assets | | | 6,505 | | | | (4,250 | ) |
Other Current Liabilities | | | 957 | | | | (9,152 | ) |
Net Cash Flows from Operating Activities | | | 250,841 | | | | 178,522 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (113,132 | ) | | | (167,412 | ) |
Change in Advances to Affiliates, Net | | | (383,537 | ) | | | - | |
Other Investing Activities | | | 4,047 | | | | (566 | ) |
Net Cash Flows Used for Investing Activities | | | (492,622 | ) | | | (167,978 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Long-term Debt – Nonaffiliated | | | 640,770 | | | | 17,376 | |
Change in Advances from Affiliates, Net | | | (128,331 | ) | | | 117,879 | |
Retirement of Long-term Debt – Nonaffiliated | | | (229,655 | ) | | | (5 | ) |
Retirement of Long-term Debt – Affiliated | | | - | | | | (100,000 | ) |
Retirement of Cumulative Preferred Stock | | | (8 | ) | | | (4 | ) |
Principal Payments for Capital Lease Obligations | | | (1,876 | ) | | | (1,790 | ) |
Dividends Paid on Common Stock | | | (37,500 | ) | | | (44,000 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (200 | ) | | | (200 | ) |
Other Financing Activities | | | 14 | | | | 436 | |
Net Cash Flows from (Used for) Financing Activities | | | 243,214 | | | | (10,308 | ) |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 1,433 | | | | 236 | |
Cash and Cash Equivalents at Beginning of Period | | | 951 | | | | 2,006 | |
Cash and Cash Equivalents at End of Period | | $ | 2,384 | | | $ | 2,242 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 36,992 | | | $ | 38,971 | |
Net Cash Paid for Income Taxes | | | 629 | | | | - | |
Noncash Acquisitions Under Capital Leases | | | 368 | | | | 20,369 | |
Government Grants Included in Accounts Receivable at March 31, | | | 572 | | | | - | |
Construction Expenditures Included in Current Liabilities at March 31, | | | 38,071 | | | | 43,262 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
INDEX OF 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. The footnotes begin on page 143.
| Footnote Reference |
| |
Significant Accounting Matters | Note 1 |
| |
Rate Matters | Note 2 |
| |
Commitments, Guarantees and Contingencies | Note 3 |
| |
Benefit Plans | Note 5 |
| |
Business Segments | Note 6 |
| |
Derivatives and Hedging | Note 7 |
| |
Fair Value Measurements | Note 8 |
| |
Income Taxes | Note 9 |
| |
Financing Activities | Note 10 |
| |
Cost Reduction Initiatives | Note 11 |
COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS
EXECUTIVE OVERVIEW
REGULATORY ACTIVITYOhio Customer Choice
Ohio Electric Security Plan FilingIn CSPCo’s service territory, various competitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service. Through March 31, 2011, approximately 7,500 CSPCo retail customers have switched from CSPCo to alternative CRES providers. As a result, in comparison to the first three months of 2010, CSPCo lost approximately $18 million of generation related gross margin through March 31, 2011. Management anticipates recovery of a portion of this lost margin through off-system sales, including PJM capacity revenues.
During Regulatory Activity
2009 the PUCO issued an order that modified and approved OPCo’s ESP which established rates through 2011. The order also limits annual rate increases for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011. The order provides a FAC for the three-year period of the ESP. Several notices of appeal are outstanding at– 2011 ESPs
In April 2011, the Supreme Court of Ohio relating to significant issues inissued an opinion addressing the determinationaspects of the approved ESP rates. OPCo filed its significantly excessive earnings test withPUCO's 2009 decision that were challenged which resulted in three reversals, only two of which may have a prospective impact. If any rate changes result from the PUCO in September 2010. Based uponPUCO’s remand proceedings, such rate changes would be prospective from the methodology proposed by OPCo indate of the SEET filing, OPCo’s 2009 return on equity was not significantly excessive. However, ifremand order through the PUCO determines that OPCo’s 2009 return on equity was significantly excessive, OPCo may be required to return a portionremaining months of its ESP revenues to customers.2011. See “Ohio Electric Security Plan Filings” section of Note 3.2.
January 2012 – May 2014 ESP
In January 2011, CSPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing for generation. The rates would be effective with the first billing cycle of January 2012 through the last billing cycle of May 2014. The SSO presents redesigned generation rates by customer class. Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013. Under the new ESP, management estimates CSPCo will have base generation increases, excluding riders, of $17 million for 2012 and $46 million for 2013. The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESP could impact the outcome of the January 2012 – May 2014 ESP, though the nature and extent of that impact is not presently known. See “Ohio Electric Security Plan Filings” section of Note 2.
Ohio Distribution Base Rate Case
In February 2011, CSPCo filed with the PUCO for an annual increase in distribution rates of $34 million. The requested increase is based upon an 11.15% return on common equity to be effective January 2012. In addition to the annual increase, CSPCo requested recovery of the projected December 31, 2012 balance of certain distribution regulatory assets of $216 million, including approximately $102 million of unrecognized equity carrying costs. These assets would be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013. The actual balance of these distribution regulatory assets as of March 31, 2011 was $98 million, excluding $57 million of unrecognized equity carrying costs. If CSPCo is not ultimately permitted to fully recover its deferrals, it would reduce future net income and cash flows and impact financial condition. See “Ohio Distribution Base Rate Case” section of Note 2.
Proposed CSPCo and OPCo Merger
In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo. Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company. The merger is also subject to regulatory approval by the FERC.In January 2011, CSPCo and OPCo anticipate completion offiled an application with the merger duringFERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo. CSPCo and OPCo requested the reorganization transaction be effective in October 2011. Decisions are pending from the PUCO and the FERC. See “Proposed CSPCo and OPCo Merger” section of Note 3.2.
LITIGATIONLitigation and Environmental Issues
In the ordinary course of business, CSPCo 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 resolution will be or the timing and amount of any loss, fine or penalty may be. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss 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 2010 Annual Report. Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 143. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.
See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 201 for additional discussion of relevant factors.
RESULTS OF OPERATIONS | | | | | |
| | | | | | |
KWH Sales/Degree Days | | | | | |
| | | | | | |
Summary of KWH Energy Sales |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in millions of KWH) |
Retail: | | | | | |
| Residential | | 2,127 | | | 2,226 |
| Commercial | | 1,995 | | | 2,002 |
| Industrial | | 1,270 | | | 1,111 |
| Miscellaneous | | 14 | | | 13 |
Total Retail | | 5,406 | | | 5,352 |
| | | | | |
Wholesale | | 863 | | | 719 |
| | | | | |
Total KWHs | | 6,269 | | | 6,071 |
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.
Summary of Heating and Cooling Degree Days |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in degree days) |
| | | | | | |
Actual - Heating (a) | | 1,928 | | | 1,965 |
Normal - Heating (b) | | 1,784 | | | 1,784 |
| | | | | | |
Actual - Cooling (c) | | 1 | | | - |
Normal - Cooling (b) | | 3 | | | 3 |
| | | | | | |
(a) | Eastern 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 cooling degree days are calculated on a 65 degree temperature base. |
First Quarter of 2011 Compared to First Quarter of 2010 | |
| | | |
Reconciliation of First Quarter of 2010 to First Quarter of 2011 | |
Net Income | |
(in millions) | |
| | | |
First Quarter of 2010 | | $ | 52 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins | | | 10 | |
Off-system Sales | | | 12 | |
Total Change in Gross Margin | | | 22 | |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | 1 | |
Depreciation and Amortization | | | (4 | ) |
Taxes Other Than Income Taxes | | | (3 | ) |
Interest Expense | | | 2 | |
Other Income | | | 1 | |
Total Expenses and Other | | | (3 | ) |
| | | | |
Income Tax Expense | | | (6 | ) |
| | | | |
First Quarter of 2011 | | $ | 65 | |
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 $10 million due to the following: |
| · | A $12 million increase in revenue due to the implementation of PUCO approved rider rates in June 2010 related to the Energy Efficiency & Peak Demand Reduction (EE/PDR) Programs. This increase in Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below. |
| · | A $10 million increase associated with the final 2009 SEET order. |
| · | A $4 million increase in revenues due to the implementation of PUCO approved rider rates in September 2010 related to the Environmental Investment Carrying Cost Rider. |
| These increases were partially offset by: |
| · | An $18 million decrease attributable to customers switching to alternative competitive retail electric service (CRES) providers. |
· | Margins from Off-system Sales increased $12 million primarily due to an increase in PJM capacity revenues, partially offset by lower trading and marketing margins. |
Total Expenses and Other and Income Tax Expense changed between years as follows:
· | Other Operation and Maintenance expenses decreased $1 million primarily due to: |
| · | A $7 million decrease in transmission expense primarily due to the Transmission Agreement modification effective November 2010, a portion of which is included in the Ohio Transmission Cost Recovery Rider. |
| · | A $3 million decrease in employee-related expenses. |
| These decreases were partially offset by: |
| · | A $12 million increase in expenses due to the implementation of PUCO approved EE/PDR programs. This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above. |
· | Depreciation and Amortization expenses increased $4 million as a result of recognizing the deferred debt and equity carrying charges on deferred fuel as permitted under the final 2009 SEET order. |
· | Taxes Other Than Income Taxes increased $3 million due to an increase in property taxes. |
· | Income Tax Expense increased $6 million primarily due to an increase in pre-tax book income, offset in part by the 2010 tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits. |
CRITICAL ACCOUNTING POLICIES AND ENVIRONMENTAL ISSUESESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.
See the “Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 201 for a discussion of accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See “Quantitative And Qualitative Disclosures About Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 201 for a discussion of market risk.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF INCOME | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| | | | | | |
| | 2011 | | | 2010 | |
REVENUES | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 503,371 | | | $ | 501,019 | |
Sales to AEP Affiliates | | | 40,725 | | | | 15,832 | |
Other Revenues | | | 506 | | | | 588 | |
TOTAL REVENUES | | | 544,602 | | | | 517,439 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 112,913 | | | | 114,441 | |
Purchased Electricity for Resale | | | 23,517 | | | | 19,645 | |
Purchased Electricity from AEP Affiliates | | | 101,611 | | | | 98,799 | |
Other Operation | | | 71,067 | | | | 77,326 | |
Maintenance | | | 29,100 | | | | 24,283 | |
Depreciation and Amortization | | | 41,426 | | | | 37,487 | |
Taxes Other Than Income Taxes | | | 50,149 | | | | 47,057 | |
TOTAL EXPENSES | | | 429,783 | | | | 419,038 | |
| | | | | | | | |
OPERATING INCOME | | | 114,819 | | | | 98,401 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest Income | | | 167 | | | | 142 | |
Carrying Costs Income | | | 3,654 | | | | 2,221 | |
Allowance for Equity Funds Used During Construction | | | 771 | | | | 921 | |
Interest Expense | | | (19,748 | ) | | | (21,784 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 99,663 | | | | 79,901 | |
| | | | | | | | |
Income Tax Expense | | | 34,105 | | | | 28,251 | |
| | | | | | | | |
NET INCOME | | | 65,558 | | | | 51,650 | |
| | | | | | | | |
Capital Stock Expense | | | 25 | | | | 39 | |
| | | | | | | | |
EARNINGS ATTRIBUTABLE TO COMMON STOCK | | $ | 65,533 | | | $ | 51,611 | |
| | | | | | | | |
The common stock of CSPCo is wholly-owned by AEP. | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S | |
EQUITY AND COMPREHENSIVE INCOME (LOSS) | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | | | | | | | | | | Accumulated | | | | |
| | | | | | | | | | | Other | | | | |
| | Common | | | Paid-in | | | Retained | | | Comprehensive | | | | |
| | Stock | | | Capital | | | Earnings | | | Income (Loss) | | | Total | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2009 | | $ | 41,026 | | | $ | 580,663 | | | $ | 788,139 | | | $ | (49,993 | ) | | $ | 1,359,835 | |
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (31,250 | ) | | | | | | | (31,250 | ) |
Capital Stock Expense | | | | | | | 39 | | | | (39 | ) | | | | | | | - | |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 1,328,585 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of | | | | | | | | | | | | | | | | | | | | |
Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $555 | | | | | | | | | | | | | | | (1,031 | ) | | | (1,031 | ) |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $333 | | | | | | | | | | | | | | | 619 | | | | 619 | |
NET INCOME | | | | | | | | | | | 51,650 | | | | | | | | 51,650 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 51,238 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – MARCH 31, 2010 | | $ | 41,026 | | | $ | 580,702 | | | $ | 808,500 | | | $ | (50,405 | ) | | $ | 1,379,823 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2010 | | $ | 41,026 | | | $ | 580,812 | | | $ | 915,713 | | | $ | (51,336 | ) | | $ | 1,486,215 | |
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (62,500 | ) | | | | | | | (62,500 | ) |
Capital Stock Expense | | | | | | | 25 | | | | (25 | ) | | | | | | | - | |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 1,423,715 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $114 | | | | | | | | | | | | | | | 213 | | | | 213 | |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $344 | | | | | | | | | | | | | | | 639 | | | | 639 | |
NET INCOME | | | | | | | | | | | 65,558 | | | | | | | | 65,558 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 66,410 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – MARCH 31, 2011 | | $ | 41,026 | | | $ | 580,837 | | | $ | 918,746 | | | $ | (50,484 | ) | | $ | 1,490,125 | |
| | | | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
ASSETS | |
March 31, 2011 and December 31, 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 1,385 | | | $ | 509 | |
Other Cash Deposits | | | 2,260 | | | | 2,260 | |
Advances to Affiliates | | | 63,706 | | | | 54,202 | |
Accounts Receivable: | | | | | | | | |
Customers | | | 50,017 | | | | 50,187 | |
Affiliated Companies | | | 44,261 | | | | 66,788 | |
Accrued Unbilled Revenues | | | 14,205 | | | | 32,821 | |
Miscellaneous | | | 4,715 | | | | 14,374 | |
Allowance for Uncollectible Accounts | | | (1,618 | ) | | | (1,584 | ) |
Total Accounts Receivable | | | 111,580 | | | | 162,586 | |
Fuel | | | 64,555 | | | | 72,882 | |
Materials and Supplies | | | 41,290 | | | | 42,033 | |
Emission Allowances | | | 26,461 | | | | 28,486 | |
Risk Management Assets | | | 22,221 | | | | 23,774 | |
Accrued Tax Benefits | | | 1,453 | | | | 8,797 | |
Regulatory Asset for Under-Recovered Fuel Costs | | | 19,199 | | | | - | |
Margin Deposits | | | 11,162 | | | | 14,762 | |
Prepayments and Other Current Assets | | | 11,066 | | | | 26,864 | |
TOTAL CURRENT ASSETS | | | 376,338 | | | | 437,155 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Generation | | | 2,719,642 | | | | 2,686,294 | |
Transmission | | | 676,250 | | | | 662,312 | |
Distribution | | | 1,804,501 | | | | 1,796,023 | |
Other Property, Plant and Equipment | | | 203,744 | | | | 203,593 | |
Construction Work in Progress | | | 142,609 | | | | 172,793 | |
Total Property, Plant and Equipment | | | 5,546,746 | | | | 5,521,015 | |
Accumulated Depreciation and Amortization | | | 1,959,482 | | | | 1,927,112 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 3,587,264 | | | | 3,593,903 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 303,741 | | | | 298,111 | |
Long-term Risk Management Assets | | | 23,080 | | | | 22,089 | |
Deferred Charges and Other Noncurrent Assets | | | 125,746 | | | | 152,932 | |
TOTAL OTHER NONCURRENT ASSETS | | | 452,567 | | | | 473,132 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 4,416,169 | | | $ | 4,504,190 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
| | | | | | | | |
| | | | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
LIABILITIES AND SHAREHOLDER'S EQUITY | |
March 31, 2011 and December 31, 2010 | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
| | (in thousands) | |
CURRENT LIABILITIES | | | | | | |
Accounts Payable: | | | | | | |
General | | $ | 80,031 | | | $ | 98,925 | |
Affiliated Companies | | | 55,640 | | | | 78,617 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 150,000 | | | | - | |
Risk Management Liabilities | | | 13,053 | | | | 15,967 | |
Customer Deposits | | | 30,222 | | | | 29,441 | |
Accrued Taxes | | | 175,816 | | | | 226,572 | |
Accrued Interest | | | 25,189 | | | | 22,533 | |
Other Current Liabilities | | | 93,112 | | | | 111,868 | |
TOTAL CURRENT LIABILITIES | | | 623,063 | | | | 583,923 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 1,288,900 | | | | 1,438,830 | |
Long-term Risk Management Liabilities | | | 7,653 | | | | 6,223 | |
Deferred Income Taxes | | | 619,951 | | | | 604,828 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 164,212 | | | | 163,888 | |
Employee Benefits and Pension Obligations | | | 135,202 | | | | 136,643 | |
Deferred Credits and Other Noncurrent Liabilities | | | 87,063 | | | | 83,640 | |
TOTAL NONCURRENT LIABILITIES | | | 2,302,981 | | | | 2,434,052 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 2,926,044 | | | | 3,017,975 | |
| | | | | | | | |
Rate Matters (Note 2) | | | | | | | | |
Commitments and Contingencies (Note 3) | | | | | | | | |
| | | | | | | | |
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 | | | 580,837 | | | | 580,812 | |
Retained Earnings | | | 918,746 | | | | 915,713 | |
Accumulated Other Comprehensive Income (Loss) | | | (50,484 | ) | | | (51,336 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | | 1,490,125 | | | | 1,486,215 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY | | $ | 4,416,169 | | | $ | 4,504,190 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 65,558 | | | $ | 51,650 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 41,426 | | | | 37,487 | |
Deferred Income Taxes | | | 31,902 | | | | 8,327 | |
Allowance for Equity Funds Used During Construction | | | (771 | ) | | | (921 | ) |
Mark-to-Market of Risk Management Contracts | | | (669 | ) | | | (11,609 | ) |
Property Taxes | | | 27,283 | | | | 24,131 | |
Fuel Over/Under-Recovery, Net | | | (4,891 | ) | | | 26,139 | |
Change in Other Noncurrent Assets | | | (9,041 | ) | | | (4,994 | ) |
Change in Other Noncurrent Liabilities | | | 5,100 | | | | (46 | ) |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 43,606 | | | | 5,553 | |
Fuel, Materials and Supplies | | | 10,033 | | | | (9,795 | ) |
Accounts Payable | | | (35,549 | ) | | | (22,402 | ) |
Accrued Taxes, Net | | | (48,059 | ) | | | (24,444 | ) |
Other Current Assets | | | 4,645 | | | | (428 | ) |
Other Current Liabilities | | | (25,526 | ) | | | (1,619 | ) |
Net Cash Flows from Operating Activities | | | 105,047 | | | | 77,029 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (45,732 | ) | | | (42,906 | ) |
Change in Other Cash Deposits | | | - | | | | 10,290 | |
Change in Advances to Affiliates, Net | | | (9,504 | ) | | | (37,818 | ) |
Acquisitions of Assets | | | (201 | ) | | | (190 | ) |
Proceeds from Sales of Assets | | | 2,439 | | | | 789 | |
Other Investing Activities | | | 12,179 | | | | - | |
Net Cash Flows Used for Investing Activities | | | (40,819 | ) | | | (69,835 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Long-term Debt – Nonaffiliated | | | - | | | | 149,625 | |
Change in Advances from Affiliates, Net | | | - | | | | (24,202 | ) |
Retirement of Long-term Debt – Affiliated | | | - | | | | (100,000 | ) |
Principal Payments for Capital Lease Obligations | | | (852 | ) | | | (1,120 | ) |
Dividends Paid on Common Stock | | | (62,500 | ) | | | (31,250 | ) |
Other Financing Activities | | | - | | | | 71 | |
Net Cash Flows Used for Financing Activities | | | (63,352 | ) | | | (6,876 | ) |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 876 | | | | 318 | |
Cash and Cash Equivalents at Beginning of Period | | | 509 | | | | 1,096 | |
Cash and Cash Equivalents at End of Period | | $ | 1,385 | | | $ | 1,414 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 16,396 | | | $ | 18,631 | |
Net Cash Paid for Income Taxes | | | 518 | | | | - | |
Noncash Acquisitions Under Capital Leases | | | 139 | | | | 8,353 | |
Government Grants Included in Accounts Receivable at March 31, | | | 1,938 | | | | - | |
Construction Expenditures Included in Current Liabilities at March 31, | | | 8,572 | | | | 13,891 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
INDEX OF 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. The footnotes begin on page 143.
| Footnote Reference |
| |
Significant Accounting Matters | Note 1 |
| |
Rate Matters | Note 2 |
| |
Commitments, Guarantees and Contingencies | Note 3 |
| |
Benefit Plans | Note 5 |
| |
Business Segments | Note 6 |
| |
Derivatives and Hedging | Note 7 |
| |
Fair Value Measurements | Note 8 |
| |
Income Taxes | Note 9 |
| |
Financing Activities | Note 10 |
| |
Cost Reduction Initiatives | Note 11 |
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE DISCUSSION AND ANALYSIS
EXECUTIVE OVERVIEW
Regulatory Activity
Cook Plant Unit 1 Fire and Shutdown
In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in a fire on the electric generator. Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $395 million. Management believes that I&M should recover a significant portion of repair and replacement costs through the turbine vendor’s warranty, insurance and the regulatory process. I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power. The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors. As a result, the replacement of the repaired turbine rotors and other equipment is scheduled for the Unit 1 planned outage in the fall of 2011. If the ultimate costs of the incident are not covered by warranty, insurance or through the related regulatory process or if any future regulatory proceedings are adverse, it could reduce future net income and cash flows and impact financial condition. See “Michigan 2009 and 2010 Power Supply Cost Recovery Reconciliations” section of Note 2 and “Cook Plant Unit 1 Fire and Shutdown” section of Note 3.
As a result of the nuclear plant situation in Japan following an earthquake, management expects the Nuclear Regulatory Commission and possibly Congress to review safety procedures and requirements for nuclear generating facilities. This review could increase procedures and testing requirements and increase future operating costs at the Cook Plant.
Litigation and Environmental Issues
In the ordinary course of business, I&M 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 resolution will be or the timing and amount of any loss, fine or penalty may be. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss 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 2010 Annual Report. Also, see Note 2 – Rate Matters and Note 3 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 143. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.
See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 201 for additional discussion of relevant factors.
RESULTS OF OPERATIONS | | | | | |
| | | | | | | |
KWH Sales/Degree Days | | | | | |
| | | | | | |
Summary of KWH Energy Sales |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in millions of KWH) |
Retail: | | | | | |
| Residential | | 1,836 | | | 1,765 |
| Commercial | | 1,263 | | | 1,208 |
| Industrial | | 1,844 | | | 1,800 |
| Miscellaneous | | 23 | | | 18 |
Total Retail | | 4,966 | | | 4,791 |
| | | | | |
Wholesale | | 2,096 | | | 1,906 |
| | | | | |
Total KWHs | | 7,062 | | | 6,697 |
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.
Summary of Heating and Cooling Degree Days |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in degree days) |
| | | | | | |
Actual - Heating (a) | | 2,392 | | | 2,174 |
Normal - Heating (b) | | 2,175 | | | 2,172 |
| | | | | | |
Actual - Cooling (c) | | - | | | - |
Normal - Cooling (b) | | 1 | | | 1 |
| | | | | | |
(a) | Eastern 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 cooling degree days are calculated on a 65 degree temperature base. |
First Quarter of 2011 Compared to First Quarter of 2010 |
| | | |
Reconciliation of First Quarter of 2010 to First Quarter of 2011 | |
Net Income | |
(in millions) | |
| | | |
First Quarter of 2010 | | $ | 45 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins | | | 13 | |
FERC Municipals and Cooperatives | | | 2 | |
Off-system Sales | | | 2 | |
Other Revenues | | | (2 | ) |
Total Change in Gross Margin | | | 15 | |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | (6 | ) |
Taxes Other Than Income Taxes | | | (1 | ) |
Other Income | | | (1 | ) |
Interest Expense | | | 1 | |
Total Expenses and Other | | | (7 | ) |
| | | | |
Income Tax Expense | | | (8 | ) |
| | | | |
First Quarter of 2011 | | $ | 45 | |
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 $13 million primarily due to the following: |
| · | An $8 million increase due to Michigan rate settlement effective in December 2010. |
| · | A $7 million increase in margins from residential sales primarily due to higher usage reflecting favorable weather. |
Total Expenses and Other and Income Tax Expense changed between years as follows:
· | Other Operation and Maintenance expenses increased $6 million primarily due to the following: |
| · | A $10 million increase in transmission expense primarily due to the Transmission Agreement modification effective November 2010. |
| This increase was partially offset by: |
| · | A $5 million decrease in administrative and general expenses. |
· | Income Tax Expense increased $8 million primarily due to an increase in pretax book income and federal income tax adjustments related to prior year tax returns. |
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.
See the “Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 201 for a discussion of accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See “Quantitative And Qualitative Disclosures About Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 201 for a discussion of market risk.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF INCOME | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| | | | | | |
| | 2011 | | | 2010 | |
REVENUES | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 456,862 | | | $ | 438,024 | |
Sales to AEP Affiliates | | | 74,868 | | | | 84,217 | |
Other Revenues - Affiliated | | | 24,331 | | | | 27,966 | |
Other Revenues - Nonaffiliated | | | 4,431 | | | | 2,849 | |
TOTAL REVENUES | | | 560,492 | | | | 553,056 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 115,062 | | | | 119,181 | |
Purchased Electricity for Resale | | | 29,292 | | | | 29,767 | |
Purchased Electricity from AEP Affiliates | | | 79,584 | | | | 82,250 | |
Other Operation | | | 133,211 | | | | 130,681 | |
Maintenance | | | 51,000 | | | | 48,444 | |
Depreciation and Amortization | | | 34,087 | | | | 33,831 | |
Taxes Other Than Income Taxes | | | 22,262 | | | | 21,032 | |
TOTAL EXPENSES | | | 464,498 | | | | 465,186 | |
| | | | | | | | |
OPERATING INCOME | | | 95,994 | | | | 87,870 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest Income | | | 696 | | | | 485 | |
Allowance for Equity Funds Used During Construction | | | 3,199 | | | | 4,435 | |
Interest Expense | | | (25,191 | ) | | | (26,101 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 74,698 | | | | 66,689 | |
| | | | | | | | |
Income Tax Expense | | | 29,271 | | | | 21,631 | |
| | | | | | | | |
NET INCOME | | | 45,427 | | | | 45,058 | |
| | | | | | | | |
Preferred Stock Dividend Requirements | | | 85 | | | | 85 | |
| | | | | | | | |
EARNINGS ATTRIBUTABLE TO COMMON STOCK | | $ | 45,342 | | | $ | 44,973 | |
| | | | | | | | |
The common stock of I&M is wholly-owned by AEP. | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S | |
EQUITY AND COMPREHENSIVE INCOME (LOSS) | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | | | | | | | | | | Accumulated | | | | |
| | | | | | | | | | | Other | | | | |
| | Common | | | Paid-in | | | Retained | | | Comprehensive | | | | |
| | Stock | | | Capital | | | Earnings | | | Income (Loss) | | | Total | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2009 | | $ | 56,584 | | | $ | 981,292 | | | $ | 656,608 | | | $ | (21,701 | ) | | $ | 1,672,783 | |
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (25,750 | ) | | | | | | | (25,750 | ) |
Preferred Stock Dividends | | | | | | | | | | | (85 | ) | | | | | | | (85 | ) |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 1,646,948 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of | | | | | | | | | | | | | | | | | | | | |
Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $422 | | | | | | | | | | | | | | | (784 | ) | | | (784 | ) |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $117 | | | | | | | | | | | | | | | 218 | | | | 218 | |
NET INCOME | | | | | | | | | | | 45,058 | | | | | | | | 45,058 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 44,492 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – MARCH 31, 2010 | | $ | 56,584 | | | $ | 981,292 | | | $ | 675,831 | | | $ | (22,267 | ) | | $ | 1,691,440 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2010 | | $ | 56,584 | | | $ | 981,294 | | | $ | 677,360 | | | $ | (20,889 | ) | | $ | 1,694,349 | |
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (18,750 | ) | | | | | | | (18,750 | ) |
Preferred Stock Dividends | | | | | | | | | | | (85 | ) | | | | | | | (85 | ) |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 1,675,514 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $286 | | | | | | | | | | | | | | | 531 | | | | 531 | |
Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | | | |
Costs, Net of Tax of $128 | | | | | | | | | | | | | | | 237 | | | | 237 | |
NET INCOME | | | | | | | | | | | 45,427 | | | | | | | | 45,427 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 46,195 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – MARCH 31, 2011 | | $ | 56,584 | | | $ | 981,294 | | | $ | 703,952 | | | $ | (20,121 | ) | | $ | 1,721,709 | |
| | | | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
ASSETS | |
March 31, 2011 and December 31, 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 912 | | | $ | 361 | |
Advances to Affiliates | | | 56,813 | | | | - | |
Accounts Receivable: | | | | | | | | |
Customers | | | 56,396 | | | | 76,193 | |
Affiliated Companies | | | 62,023 | | | | 149,169 | |
Accrued Unbilled Revenues | | | 28,066 | | | | 19,449 | |
Miscellaneous | | | 11,714 | | | | 10,968 | |
Allowance for Uncollectible Accounts | | | (1,687 | ) | | | (1,692 | ) |
Total Accounts Receivable | | | 156,512 | | | | 254,087 | |
Fuel | | | 79,584 | | | | 87,551 | |
Materials and Supplies | | | 177,955 | | | | 178,331 | |
Risk Management Assets | | | 26,436 | | | | 27,526 | |
Accrued Tax Benefits | | | 68,504 | | | | 71,113 | |
Deferred Cook Plant Fire Costs | | | 46,532 | | | | 45,752 | |
Prepayments and Other Current Assets | | | 24,607 | | | | 33,713 | |
TOTAL CURRENT ASSETS | | | 637,855 | | | | 698,434 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Generation | | | 3,781,344 | | | | 3,774,262 | |
Transmission | | | 1,197,343 | | | | 1,188,665 | |
Distribution | | | 1,427,078 | | | | 1,411,095 | |
Other Property, Plant and Equipment (including nuclear fuel and coal mining) | | | 715,565 | | | | 719,708 | |
Construction Work in Progress | | | 301,781 | | | | 301,534 | |
Total Property, Plant and Equipment | | | 7,423,111 | | | | 7,395,264 | |
Accumulated Depreciation, Depletion and Amortization | | | 3,153,696 | | | | 3,124,998 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 4,269,415 | | | | 4,270,266 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 534,389 | | | | 556,254 | |
Spent Nuclear Fuel and Decommissioning Trusts | | | 1,558,535 | | | | 1,515,227 | |
Long-term Risk Management Assets | | | 31,923 | | | | 31,485 | |
Deferred Charges and Other Noncurrent Assets | | | 85,384 | | | | 77,229 | |
TOTAL OTHER NONCURRENT ASSETS | | | 2,210,231 | | | | 2,180,195 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 7,117,501 | | | $ | 7,148,895 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
| | | | | | | | |
| | | | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
LIABILITIES AND SHAREHOLDERS' EQUITY | |
March 31, 2011 and December 31, 2010 | |
(dollars in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
CURRENT LIABILITIES | | | | | | |
Advances from Affiliates | | $ | - | | | $ | 42,769 | |
Accounts Payable: | | | | | | | | |
General | | | 84,677 | | | | 121,665 | |
Affiliated Companies | | | 69,464 | | | | 105,221 | |
Long-term Debt Due Within One Year - Nonaffiliated | | | | | | | | |
(March 31, 2011 and December 31, 2010 amounts include $78,332 and $77,457, | | | | | | | | |
respectively, related to DCC Fuel) | | | 155,332 | | | | 154,457 | |
Risk Management Liabilities | | | 13,663 | | | | 16,785 | |
Customer Deposits | | | 29,240 | | | | 29,264 | |
Accrued Taxes | | | 78,574 | | | | 62,637 | |
Accrued Interest | | | 23,045 | | | | 27,444 | |
Other Current Liabilities | | | 142,392 | | | | 140,710 | |
TOTAL CURRENT LIABILITIES | | | 596,387 | | | | 700,952 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 1,843,771 | | | | 1,849,769 | |
Long-term Risk Management Liabilities | | | 7,992 | | | | 6,530 | |
Deferred Income Taxes | | | 780,312 | | | | 760,105 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 866,458 | | | | 852,197 | |
Asset Retirement Obligations | | | 974,935 | | | | 963,029 | |
Deferred Credits and Other Noncurrent Liabilities | | | 317,865 | | | | 313,892 | |
TOTAL NONCURRENT LIABILITIES | | | 4,791,333 | | | | 4,745,522 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 5,387,720 | | | | 5,446,474 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 8,072 | | | | 8,072 | |
| | | | | | | | |
Rate Matters (Note 2) | | | | | | | | |
Commitments and Contingencies (Note 3) | | | | | | | | |
| | | | | | | | |
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 | | | 981,294 | | | | 981,294 | |
Retained Earnings | | | 703,952 | | | | 677,360 | |
Accumulated Other Comprehensive Income (Loss) | | | (20,121 | ) | | | (20,889 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | | 1,721,709 | | | | 1,694,349 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 7,117,501 | | | $ | 7,148,895 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 45,427 | | | $ | 45,058 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 34,087 | | | | 33,831 | |
Deferred Income Taxes | | | 25,087 | | | | 18,442 | |
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net | | | 11,616 | | | | (20,025 | ) |
Allowance for Equity Funds Used During Construction | | | (3,199 | ) | | | (4,435 | ) |
Mark-to-Market of Risk Management Contracts | | | (658 | ) | | | (20,345 | ) |
Amortization of Nuclear Fuel | | | 34,240 | | | | 30,090 | |
Fuel Over/Under Recovery, Net | | | 4,156 | | | | 16,439 | |
Change in Other Noncurrent Assets | | | (6,066 | ) | | | (11,056 | ) |
Change in Other Noncurrent Liabilities | | | 13,327 | | | | 28,926 | |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 97,575 | | | | 28,078 | |
Fuel, Materials and Supplies | | | 8,343 | | | | (18,972 | ) |
Accounts Payable | | | (71,206 | ) | | | 13,171 | |
Accrued Taxes, Net | | | 14,479 | | | | 23,964 | |
Other Current Assets | | | (1,475 | ) | | | (13,044 | ) |
Other Current Liabilities | | | 3,865 | | | | 38,068 | |
Net Cash Flows from Operating Activities | | | 209,598 | | | | 188,190 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (54,733 | ) | | | (104,796 | ) |
Change in Advances to Affiliates, Net | | | (56,813 | ) | | | 28,826 | |
Purchases of Investment Securities | | | (305,945 | ) | | | (247,632 | ) |
Sales of Investment Securities | | | 287,761 | | | | 232,078 | |
Acquisitions of Nuclear Fuel | | | (27,132 | ) | | | (37,616 | ) |
Other Investing Activities | | | 17,029 | | | | 500 | |
Net Cash Flows Used for Investing Activities | | | (139,833 | ) | | | (128,640 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Long-term Debt - Nonaffiliated | | | 76,864 | | | | - | |
Change in Advances from Affiliates, Net | | | (42,769 | ) | | | - | |
Retirement of Long-term Debt - Nonaffiliated | | | (82,354 | ) | | | - | |
Retirement of Long-term Debt - Affiliated | | | - | | | | (25,000 | ) |
Principal Payments for Capital Lease Obligations | | | (2,128 | ) | | | (8,524 | ) |
Dividends Paid on Common Stock | | | (18,750 | ) | | | (25,750 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (85 | ) | | | (85 | ) |
Other Financing Activities | | | 8 | | | | 24 | |
Net Cash Flows Used for Financing Activities | | | (69,214 | ) | | | (59,335 | ) |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 551 | | | | 215 | |
Cash and Cash Equivalents at Beginning of Period | | | 361 | | | | 779 | |
Cash and Cash Equivalents at End of Period | | $ | 912 | | | $ | 994 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 28,542 | | | $ | 30,056 | |
Net Cash Paid (Received) for Income Taxes | | | (1,033 | ) | | | - | |
Noncash Acquisitions Under Capital Leases | | | 693 | | | | 8,476 | |
Construction Expenditures Included in Current Liabilities at March 31, | | | 21,651 | | | | 29,496 | |
Acquisition of Nuclear Fuel Included in Current Liabilities at March 31, | | | 377 | | | | 2,705 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX OF 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. The footnotes begin on page 143.
| Footnote Reference |
| |
Significant Accounting Matters | Note 1 |
| |
Rate Matters | Note 2 |
| |
Commitments, Guarantees and Contingencies | Note 3 |
| |
Benefit Plans | Note 5 |
| |
Business Segments | Note 6 |
| |
Derivatives and Hedging | Note 7 |
| |
Fair Value Measurements | Note 8 |
| |
Income Taxes | Note 9 |
| |
Financing Activities | Note 10 |
| |
Cost Reduction Initiatives | Note 11 |
OHIO POWER COMPANY CONSOLIDATED
OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT’S DISCUSSION AND ANALYSIS
EXECUTIVE OVERVIEW
Ohio Customer Choice
In OPCo’s service territory, various competitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service. Through March 31, 2011, approximately 300 OPCo retail customers have switched from OPCo to alternative CRES providers. As a result, in comparison to the first three months of 2010, OPCo lost approximately $600 thousand of generation related gross margin through March 31, 2011. Management anticipates recovery of a portion of this lost margin through off-system sales, including PJM capacity revenues.
Regulatory Activity
2009 – 2011 ESPs
In April 2011, the Supreme Court of Ohio issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged which resulted in three reversals, only two of which may have a prospective impact. If any rate changes result from the PUCO’s remand proceedings, such rate changes would be prospective from the date of the remand order through the remaining months of 2011. See “Ohio Electric Security Plan Filings” section of Note 2.
January 2012 – May 2014 ESP
In January 2011, OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing for generation effective with the first billing cycle of January 2012 through the last billing cycle of May 2014. The SSO presents redesigned generation rates by customer class. Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013. Under the new ESP, management estimates OPCo will have base generation increases, excluding riders, of $48 million for 2012 and $60 million for 2013. The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESP could impact the outcome of the January 2012 – May 2014 ESP, though the nature and extent of that impact is not presently known. See “Ohio Electric Security Plan Filings” section of Note 2.
Ohio Distribution Base Rate Case
In February 2011, OPCo filed with the PUCO for an annual increase in distribution rates of $60 million. The requested increase is based upon an 11.15% return on common equity to be effective January 2012. In addition to the annual increase, OPCo requested recovery of the projected December 31, 2012 balance of certain distribution regulatory assets of $159 million including approximately $84 million of unrecognized equity carrying costs. These assets would be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013. The actual balance of these distribution regulatory assets as of March 31, 2011 was $63 million excluding $42 million of unrecognized equity carrying costs. If OPCo is not ultimately permitted to fully recover its deferrals, it would reduce future net income and cash flows and impact financial condition.
Proposed CSPCo and OPCo Merger
In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo. Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company. In January 2011, CSPCo and OPCo filed an application with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo. CSPCo and OPCo requested the reorganization transaction be effective in October 2011. Decisions are pending from the PUCO and the FERC.
Litigation and Environmental Issues
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 resolution will be or the timing and amount of any loss, fine or penalty may be. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss 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 20092010 Annual Report. Also, see Note 32 – Rate Matters and Note 43 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condense dCondensed Financial Statements beginning on page 161.143. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.
See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 230201 for additional discussion of relevant factors.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTSRESULTS OF OPERATIONS | | | | | |
| | | | | | |
KWH Sales/Degree Days | | | | | |
| | | | | | |
Summary of KWH Energy Sales |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in millions of KWH) |
Retail: | | | | | |
| Residential | | 2,324 | | | 2,284 |
| Commercial | | 1,393 | | | 1,359 |
| Industrial | | 3,275 | | | 3,058 |
| Miscellaneous | | 20 | | | 20 |
Total Retail | | 7,012 | | | 6,721 |
| | | | | |
Wholesale | | 1,907 | | | 1,342 |
| | | | | |
Total KWHs | | 8,919 | | | 8,063 |
See the “Critical Accounting PoliciesCooling degree days and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries”heating degree days are metrics commonly used in the 2009 Annual Report forutility industry as a discussionmeasure of the estimates and judgments required for regulatory accounting, revenue recognition, the valuationimpact of long-lived assets and pension and other postretirement benefits.weather on net income.
See the “New Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230 for a discussion of the adoption and impact of new accounting pronouncements.Summary of Heating and Cooling Degree Days |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in degree days) |
| | | | | | |
Actual - Heating (a) | | 2,242 | | | 2,157 |
Normal - Heating (b) | | 2,042 | | | 2,043 |
| | | | | | |
Actual - Cooling (c) | | 1 | | | - |
Normal - Cooling (b) | | 1 | | | 1 |
| | | | | | |
(a) | Eastern 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 cooling degree days are calculated on a 65 degree temperature base. |
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES
See “Quantitative And Qualitative Disclosures About Risk Management Activities” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230 for a discussion of risk management activities.
OHIO POWER COMPANY CONSOLIDATED | |
CONDENSED CONSOLIDATED STATEMENTS OF INCOME | |
For the Three and Nine Months Ended September 30, 2010 and 2009 | |
(in thousands) | |
(Unaudited) | |
| |
| | Three Months Ended | | | Nine Months Ended | |
| | 2010 | | | 2009 | | | 2010 | | | 2009 | |
REVENUES | | | | | | | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 583,084 | | | $ | 481,049 | | | $ | 1,617,206 | | | $ | 1,463,200 | |
Sales to AEP Affiliates | | | 263,236 | | | | 276,947 | | | | 792,565 | | | | 714,639 | |
Other Revenues - Affiliated | | | 5,065 | | | | 5,646 | | | | 16,794 | | | | 19,415 | |
Other Revenues - Nonaffiliated | | | 4,474 | | | | 2,329 | | | | 12,531 | | | | 9,445 | |
TOTAL REVENUES | | | 855,859 | | | | 765,971 | | | | 2,439,096 | | | | 2,206,699 | |
| | | | | | | | | | | | | | | | |
EXPENSES | | | | | | | | | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 284,857 | | | | 238,574 | | | | 836,048 | | | | 681,523 | |
Purchased Electricity for Resale | | | 42,840 | | | | 42,160 | | | | 120,476 | | | | 138,398 | |
Purchased Electricity from AEP Affiliates | | | 36,004 | | | | 19,782 | | | | 79,778 | | | | 56,989 | |
Other Operation | | | 106,314 | | | | 91,162 | | | | 341,887 | | | | 287,009 | |
Maintenance | | | 52,448 | | | | 50,703 | | | | 172,151 | | | | 168,893 | |
Depreciation and Amortization | | | 91,072 | | | | 89,169 | | | | 270,294 | | | | 262,576 | |
Taxes Other Than Income Taxes | | | 52,261 | | | | 48,300 | | | | 157,433 | | | | 146,274 | |
TOTAL EXPENSES | | | 665,796 | | | | 579,850 | | | | 1,978,067 | | | | 1,741,662 | |
| | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 190,063 | | | | 186,121 | | | | 461,029 | | | | 465,037 | |
| | | | | | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | | | | | |
Interest Income | | | 583 | | | | 242 | | | | 1,322 | | | | 1,002 | |
Carrying Costs Income | | | 6,324 | | | | 3,143 | | | | 16,879 | | | | 7,152 | |
Allowance for Equity Funds Used During Construction | | | 947 | | | | 1,081 | | | | 2,964 | | | | 1,849 | |
Interest Expense | | | (39,013 | ) | | | (40,614 | ) | | | (118,065 | ) | | | (114,536 | ) |
| | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 158,904 | | | | 149,973 | | | | 364,129 | | | | 360,504 | |
| | | | | | | | | | | | | | | | |
Income Tax Expense | | | 58,039 | | | | 53,398 | | | | 133,813 | | | | 127,408 | |
| | | | | | | | | | | | | | | | |
NET INCOME | | | 100,865 | | | | 96,575 | | | | 230,316 | | | | 233,096 | |
| | | | | | | | | | | | | | | | |
Less: Net Income Attributable to Noncontrolling Interest | | | - | | | | 1,026 | | | | - | | | | 2,042 | |
| | | | | | | | | | | | | | | | |
NET INCOME ATTRIBUTABLE TO OPCo | | | | | | | | | | | | | | | | |
SHAREHOLDERS | | | 100,865 | | | | 95,549 | | | | 230,316 | | | | 231,054 | |
| | | | | | | | | | | | | | | | |
Less: Preferred Stock Dividend Requirements | | | 183 | | | | 183 | | | | 549 | | | | 549 | |
| | | | | | | | | | | | | | | | |
EARNINGS ATTRIBUTABLE TO OPCo COMMON | | | | | | | | | | | | | | | | |
SHAREHOLDER | | $ | 100,682 | | | $ | 95,366 | | | $ | 229,767 | | | $ | 230,505 | |
| | | | | | | | | | | | | | | | |
The common stock of OPCo is wholly-owned by AEP. | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | |
OHIO POWER COMPANY CONSOLIDATED |
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN |
EQUITY AND COMPREHENSIVE INCOME (LOSS) |
For the Nine Months Ended September 30, 2010 and 2009 |
(in thousands) |
(Unaudited) |
|
| | OPCo Common Shareholder | | | | | | |
| | | | | | | | | | | Accumulated | | | | | |
| | | | | | | | | | | Other | | | | | |
| | Common | | Paid-in | | Retained | | Comprehensive | | Noncontrolling | | |
| | Stock | | Capital | | Earnings | | Income (Loss) | | Interest | | Total |
| | | | | | | | | | | | | | | | | | |
TOTAL EQUITY – DECEMBER 31, 2008 | | $ | 321,201 | | $ | 536,640 | | $ | 1,697,962 | | $ | (133,858) | | $ | 16,799 | | $ | 2,438,744 |
| | | | | | | | | | | | | | | | | | |
Capital Contribution from Parent | | | | | | 550,000 | | | | | | | | | | | | 550,000 |
Common Stock Dividends - Affiliated | | | | | | | | | (50,000) | | | | | | | | | (50,000) |
Common Stock Dividends - Nonaffiliated | | | | | | | | | | | | | | | (2,042) | | | (2,042) |
Preferred Stock Dividends | | | | | | | | | (549) | | | | | | | | | (549) |
Purchase of JMG | | | | | | 54,431 | | | | | | | | | (17,910) | | | 36,521 |
Other Changes in Equity | | | | | | | | | | | | | | | 1,111 | | | 1,111 |
SUBTOTAL – EQUITY | | | | | | | | | | | | | | | | | | 2,973,785 |
| | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges, Net of Tax of $4,946 | | | | | | | | | | | | 9,185 | | | | | | 9,185 |
| | Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | |
| | | Costs, Net of Tax of $2,566 | | | | | | | | | | | | 4,765 | | | | | | 4,765 |
NET INCOME | | | | | | | | | 231,054 | | | | | | 2,042 | | | 233,096 |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | 247,046 |
| | | | | | | | | | | | | | | | | | |
TOTAL EQUITY – SEPTEMBER 30, 2009 | | $ | 321,201 | | $ | 1,141,071 | | $ | 1,878,467 | | $ | (119,908) | | $ | - | | $ | 3,220,831 |
| | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | |
| | EQUITY – DECEMBER 31, 2009 | | $ | 321,201 | | $ | 1,123,149 | | $ | 1,908,803 | | $ | (118,458) | | $ | - | | $ | 3,234,695 |
| | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | (246,575) | | | | | | | | | (246,575) |
Preferred Stock Dividends | | | | | | | | | (549) | | | | | | | | | (549) |
SUBTOTAL – COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | |
| | EQUITY | | | | | | | | | | | | | | | | | | 2,987,571 |
| | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), Net of | | | | | | | | | | | | | | | | | | |
| Taxes: | | | | | | | | | | | | | | | | | | |
| | Cash Flow Hedges, Net of Tax of $1,158 | | | | | | | | | | | | (2,150) | | | | | | (2,150) |
| | Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | | | | |
| | | Costs, Net of Tax of $2,846 | | | | | | | | | | | | 5,285 | | | | | | 5,285 |
NET INCOME | | | | | | | | | 230,316 | | | | | | | | | 230,316 |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | 233,451 |
| | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | |
| | EQUITY – SEPTEMBER 30, 2010 | | $ | 321,201 | | $ | 1,123,149 | | $ | 1,891,995 | | $ | (115,323) | | $ | - | | $ | 3,221,022 |
| | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. |
OHIO POWER COMPANY CONSOLIDATED | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
ASSETS | |
September 30, 2010 and December 31, 2009 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2010 | | | 2009 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 1,354 | | | $ | 1,984 | |
Advances to Affiliates | | | 290,714 | | | | 438,352 | |
Accounts Receivable: | | | | | | | | |
Customers | | | 57,695 | | | | 60,711 | |
Affiliated Companies | | | 144,481 | | | | 200,579 | |
Accrued Unbilled Revenues | | | 18,116 | | | | 15,021 | |
Miscellaneous | | | 2,006 | | | | 2,701 | |
Allowance for Uncollectible Accounts | | | (2,703 | ) | | | (2,665 | ) |
Total Accounts Receivable | | | 219,595 | | | | 276,347 | |
Fuel | | | 256,594 | | | | 336,866 | |
Materials and Supplies | | | 121,154 | | | | 115,486 | |
Risk Management Assets | | | 44,849 | | | | 50,048 | |
Accrued Tax Benefits | | | 33,414 | | | | 143,473 | |
Prepayments and Other Current Assets | | | 31,545 | | | | 26,301 | |
TOTAL CURRENT ASSETS | | | 999,219 | | | | 1,388,857 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Production | | | 6,837,111 | | | | 6,731,469 | |
Transmission | | | 1,219,276 | | | | 1,166,557 | |
Distribution | | | 1,610,866 | | | | 1,567,871 | |
Other Property, Plant and Equipment | | | 379,362 | | | | 348,718 | |
Construction Work in Progress | | | 149,300 | | | | 198,843 | |
Total Property, Plant and Equipment | | | 10,195,915 | | | | 10,013,458 | |
Accumulated Depreciation and Amortization | | | 3,548,026 | | | | 3,318,896 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 6,647,889 | | | | 6,694,562 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 886,214 | | | | 742,905 | |
Long-term Risk Management Assets | | | 36,823 | | | | 28,003 | |
Deferred Charges and Other Noncurrent Assets | | | 114,312 | | | | 184,812 | |
TOTAL OTHER NONCURRENT ASSETS | | | 1,037,349 | | | | 955,720 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 8,684,457 | | | $ | 9,039,139 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | |
| | | | | | | | |
| | | | | | | | |
| | | | | | |
OHIO POWER COMPANY CONSOLIDATED | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
LIABILITIES AND SHAREHOLDERS' EQUITY | |
September 30, 2010 and December 31, 2009 | |
(Unaudited) | |
| |
| | 2010 | | | 2009 | |
| | (in thousands) | |
CURRENT LIABILITIES | | | | | | |
Accounts Payable: | | | | | | |
General | | $ | 147,690 | | | $ | 182,848 | |
Affiliated Companies | | | 65,550 | | | | 92,766 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 200,000 | | | | 679,450 | |
Risk Management Liabilities | | | 22,293 | | | | 24,391 | |
Customer Deposits | | | 28,110 | | | | 22,409 | |
Accrued Taxes | | | 130,219 | | | | 203,335 | |
Accrued Interest | | | 46,335 | | | | 46,431 | |
Other Current Liabilities | | | 106,736 | | | | 104,889 | |
TOTAL CURRENT LIABILITIES | | | 746,933 | | | | 1,356,519 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 2,529,386 | | | | 2,363,055 | |
Long-term Debt – Affiliated | | | 200,000 | | | | 200,000 | |
Long-term Risk Management Liabilities | | | 11,978 | | | | 12,510 | |
Deferred Income Taxes | | | 1,437,077 | | | | 1,302,939 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 128,278 | | | | 128,187 | |
Employee Benefits and Pension Obligations | | | 212,393 | | | | 269,485 | |
Deferred Credits and Other Noncurrent Liabilities | | | 180,763 | | | | 155,122 | |
TOTAL NONCURRENT LIABILITIES | | | 4,699,875 | | | | 4,431,298 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 5,446,808 | | | | 5,787,817 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 16,627 | | | | 16,627 | |
| | | | | | | | |
Rate Matters (Note 3) | | | | | | | | |
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 | | | 1,123,149 | | | | 1,123,149 | |
Retained Earnings | | | 1,891,995 | | | | 1,908,803 | |
Accumulated Other Comprehensive Income (Loss) | | | (115,323 | ) | | | (118,458 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | | 3,221,022 | | | | 3,234,695 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | | $ | 8,684,457 | | | $ | 9,039,139 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | |
OHIO POWER COMPANY CONSOLIDATED | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |
For the Nine Months Ended September 30, 2010 and 2009 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2010 | | | 2009 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 230,316 | | | $ | 233,096 | |
Adjustments to Reconcile Net Income to Net Cash Flows from | | | | | | | | |
Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 270,294 | | | | 262,576 | |
Deferred Income Taxes | | | 126,128 | | | | 213,458 | |
Carrying Costs Income | | | (16,879 | ) | | | (7,152 | ) |
Allowance for Equity Funds Used During Construction | | | (2,964 | ) | | | (1,849 | ) |
Mark-to-Market of Risk Management Contracts | | | (7,726 | ) | | | (15,226 | ) |
Pension Contributions to Qualified Plan Trust | | | (47,174 | ) | | | - | |
Property Taxes | | | 72,392 | | | | 66,976 | |
Fuel Over/Under-Recovery, Net | | | (115,926 | ) | | | (242,392 | ) |
Change in Other Noncurrent Assets | | | (4,136 | ) | | | 12,690 | |
Change in Other Noncurrent Liabilities | | | 1,009 | | | | 40,709 | |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 56,752 | | | | 15,155 | |
Fuel, Materials and Supplies | | | 74,604 | | | | (180,514 | ) |
Accounts Payable | | | (45,601 | ) | | | (138,828 | ) |
Accrued Taxes, Net | | | 36,534 | | | | (103,965 | ) |
Other Current Assets | | | (5,170 | ) | | | (4,164 | ) |
Other Current Liabilities | | | 5,019 | | | | (13,768 | ) |
Net Cash Flows from Operating Activities | | | 627,472 | | | | 136,802 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (207,663 | ) | | | (342,633 | ) |
Change in Advances to Affiliates, Net | | | 147,638 | | | | (367,743 | ) |
Acquisitions of Assets | | | (4,876 | ) | | | (1,053 | ) |
Proceeds from Sales of Assets | | | 10,406 | | | | 31,253 | |
Other Investing Activities | | | (156 | ) | | | 5,529 | |
Net Cash Flows Used for Investing Activities | | | (54,651 | ) | | | (674,647 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Capital Contribution from Parent | | | - | | | | 550,000 | |
Issuance of Long-term Debt – Nonaffiliated | | | 202,382 | | | | 494,078 | |
Change in Advances from Affiliates, Net | | | - | | | | (133,887 | ) |
Retirement of Long-term Debt – Nonaffiliated | | | (518,580 | ) | | | (295,500 | ) |
Retirement of Cumulative Preferred Stock | | | - | | | | (1 | ) |
Principal Payments for Capital Lease Obligations | | | (5,886 | ) | | | (3,435 | ) |
Dividends Paid on Common Stock – Nonaffiliated | | | - | | | | (2,042 | ) |
Dividends Paid on Common Stock – Affiliated | | | (246,575 | ) | | | (50,000 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (549 | ) | | | (549 | ) |
Acquisition of JMG Noncontrolling Interest | | | - | | | | (28,221 | ) |
Other Financing Activities | | | (4,243 | ) | | | (2,327 | ) |
Net Cash Flows from (Used for) Financing Activities | | | (573,451 | ) | | | 528,116 | |
| | | | | | | | |
Net Decrease in Cash and Cash Equivalents | | | (630 | ) | | | (9,729 | ) |
Cash and Cash Equivalents at Beginning of Period | | | 1,984 | | | | 12,679 | |
Cash and Cash Equivalents at End of Period | | $ | 1,354 | | | $ | 2,950 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 116,140 | | | $ | 119,763 | |
Net Cash Paid (Received) for Income Taxes | | | (110,627 | ) | | | (23,241 | ) |
Noncash Acquisitions Under Capital Leases | | | 23,645 | | | | 2,022 | |
Construction Expenditures Included in Accounts Payable at September 30, | | | 13,156 | | | | 15,527 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | |
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. The footnotes begin on page 161.
| 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 6 |
Business Segments | Note 7 |
Derivatives and Hedging | Note 8 |
Fair Value Measurements | Note 9 |
Income Taxes | Note 10 |
Financing Activities | Note 11 |
Cost Reduction Initiatives | Note 12First Quarter of 2011 Compared to First Quarter of 2010 |
| | | |
Reconciliation of First Quarter of 2010 to First Quarter of 2011 | |
Net Income | |
(in millions) | |
| | | |
First Quarter of 2010 | | $ | 92 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins | | | 22 | |
Transmission Revenues | | | 3 | |
Other Revenues | | | 1 | |
Total Change in Gross Margin | | | 26 | |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | (19 | ) |
Depreciation and Amortization | | | (3 | ) |
Taxes Other Than Income Taxes | | | (2 | ) |
Carrying Costs Income | | | 2 | |
Interest Expense | | | 3 | |
Total Expenses and Other | | | (19 | ) |
| | | | |
Income Tax Expense | | | 1 | |
| | | | |
First Quarter of 2011 | | $ | 100 | |
PUBLIC SERVICE COMPANY OF OKLAHOMA
PUBLIC SERVICE COMPANY OF OKLAHOMA | |
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS | |
| | | |
RESULTS OF OPERATIONS | | | |
| | | |
Third Quarter of 2010 Compared to Third Quarter of 2009 | |
| | | |
Reconciliation of Third Quarter of 2009 to Third Quarter of 2010 | |
Net Income | |
(in millions) | |
| | | |
Third Quarter of 2009 | | $ | 44 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins (a) | | | 29 | |
Transmission Revenues | | | (2 | ) |
Total Change in Gross Margin | | | 27 | |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | (4 | ) |
Depreciation and Amortization | | | 1 | |
Taxes Other Than Income Taxes | | | (1 | ) |
Other Income | | | (1 | ) |
Interest Expense | | | (2 | ) |
Total Expenses and Other | | | (7 | ) |
| | | | |
Income Tax Expense | | | (9 | ) |
| | | . | |
Third Quarter of 2010 | | $ | 55 | |
| | | | |
(a)Includes firm wholesale sales to municipals and cooperatives. | |
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 $29$22 million primarily due to the following: |
| | · | A $19$14 million increase in weather-related usage primarilyrevenue due to a 34%the implementation of PUCO approved rider rates in June 2010 related to the Energy Efficiency & Peak Demand Reduction (EE/PDR) Programs. This increase in cooling degree days.Retail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below. |
| | · | A $15$13 million increase in revenues due to increases in residential, commercial and industrial customer usage. The industrial increase was driven primarily resulting fromby increased Ormet load. |
| · | A $7 million increase in revenues due to the implementation of PUCO approved rider rates in September 2010 related to the Environmental Investment Carrying Cost Rider. |
| · | A $5 million increase in revenues due to a January 2011 Universal Service Fund surcharge rate increases, including revenue increases from rate riders.increase. This increase in retail margins hadRetail Margins was offset by a corresponding increase in Other Operation and Maintenance as discussed below. |
| These increases were partially offset by: |
| · | A $12 million decrease in capacity settlements under the Interconnection Agreement. |
· | Transmission Revenues increased $3 million primarily due to the Transmission Agreement modification effective November 2010, a portion of $4 million related to riders/trackers recognizedwhich is included in other expense items.the Ohio Transmission Cost Recovery Rider. |
Total Expenses and Other and Income Tax Expense changed between years as follows:
| · | Other Operation and Maintenanceexpenses increased $4$19 million primarily due to planned generation plant maintenance.the following: |
| · | A $14 million increase in expenses due to the implementation of PUCO approved EE/PDR programs. This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above. |
| · | A $7 million increase due to a favorable 2010 employee benefit adjustment. |
| · | A $6 million increase in maintenance expenses from planned and forced outages at various plants. |
| · | A $5 million increase in remitted Universal Service Fund surcharge payments to the Ohio Department of Development to fund an energy assistance program for qualified Ohio customers. This increase in Other Operation and Maintenance expense was offset by a corresponding increase in Retail Margins as discussed above. |
| These increases were partially offset by: |
| · | An $11 million gain from the sale of land in January 2011. |
· | Income Tax Expense increased $9decreased $1 million primarily due to the 2010 tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits, partially offset by an increase in pretax book income. |
Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009 |
| | | | |
Reconciliation of Nine Months Ended September 30, 2009 to Nine Months Ended September 30, 2010 |
Net Income |
(in millions) |
| | | | |
Nine Months Ended September 30, 2009 | | $ | 74 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins (a) | | | 52 | |
Transmission Revenues | | | 1 | |
Other Revenues | | | (1) | |
Total Change in Gross Margin | | | 52 | |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | (43) | |
Depreciation and Amortization | | | 3 | |
Other Income | | | (3) | |
Interest Expense | | | (5) | |
Total Expenses and Other | | | (48) | |
| | | | |
Income Tax Expense | | | (3) | |
| | | | |
Nine Months Ended September 30, 2010 | | $ | 75 | |
| | | | |
(a)Includes firm wholesale sales to municipals and cooperatives. |
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 $52 million primarily due to the following:
|
| | · | A $34 million increase primarily resulting from rate increases, including revenue increases from rate riders. This increase in retail margins had corresponding increases of $10 million related to riders/trackers recognized in other expense items. |
| | · | A $28 million increase in weather-related usage primarily due to a 27% increase in heating degree days and a 26% increase in cooling degree days. |
Total Expenses and Other changed between years as follows:
| · | Other Operation and Maintenance expenses increased $43 million primarily due to the following:
|
| | · | A $23 million increase primarily due to expenses related to the cost reduction initiatives. |
| | · | An $8 million increase in plant maintenance expense resulting primarily from the 2009 deferral of generation maintenance expenses as a result of PSO’s base rate case. |
| | · | A $7 million increase in employee-related expenses. |
| · | Interest Expense increased $5 million primarily due to an increase in long-term borrowings in the last half of 2009.
|
FINANCIAL CONDITION
LIQUIDITY
PSOOPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity. PSOOPCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures. See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 230201 for additional discussion of liquidity.
Credit Ratings
Downgrades inOPCo’s ultimate access to capital markets may depend on its credit ratingsratings. In addition, a credit rating downgrade of OPCo by one of the rating agencies could increase PSO’sOPCo’s borrowing costs. Failure to maintain investment grade ratings may constrain OPCo’s ability to participate in the Utility Money Pool or the amount of OPCo’s receivables securitized by AEP Credit. Counterparty concerns about OPCo’s credit quality could subject OPCo to additional collateral demands under adequate assurance clauses under derivative and non-derivative energy contracts.
CASH FLOW
Cash flows for the ninethree months ended September 30,March 31, 2011 and 2010 and 2009 were as follows:
| | 2010 | | | 2009 | | | 2011 | | | 2010 | |
| | (in thousands) | | | (in thousands) | |
Cash and Cash Equivalents at Beginning of Period | | $ | 796 | | | $ | 1,345 | | | $ | 440 | | | $ | 1,984 | |
Net Cash Flows from Operating Activities | | | 107,685 | | | | 232,759 | | | | 229,340 | | | | 251,324 | |
Net Cash Flows Used for Investing Activities | | | (90,344 | ) | | | (142,945 | ) | | | (10,877 | ) | | | (258,305 | ) |
Net Cash Flows Used For Financing Activities | | | (16,550 | ) | | | (89,852 | ) | |
Net Cash Flows from (Used for) Financing Activities | | | | (217,699 | ) | | | 6,150 | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 791 | | | | (38 | ) | | | 764 | | | | (831 | ) |
Cash and Cash Equivalents at End of Period | | $ | 1,587 | | | $ | 1,307 | | | $ | 1,204 | | | $ | 1,153 | |
Operating Activities
Net Cash Flows from Operating Activities were $108$229 million in 2010. PSO2011. OPCo produced Net Income of $75$100 million during the period and had noncash expense items of $81$92 million for Depreciation and Amortization, and $44$29 million for Deferred Income Taxes and $25 million for Property 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 number of items. Accounts Payable had a $51 million outflow primarily due to timing differences of payments. Accounts Receivable, Net had a $45 million inflow primarily due to a settlement with AEP Ohio Transmission Company and settlements of allowance sales to affiliated companies. Fuel, Materials and Supplies had a $45 million inflow primarily due to a decrease in coal inventory reflecting increased customer usage for electricity. The $23 million outflow from Accrued Taxes, Net is primarily due to temporary timing differences of payments for property taxes partially offset by an increase of federal income tax related accruals.
Net Cash Flows from Operating Activities were $251 million in 2010. OPCo produced Net Income of $92 million during the period and noncash expense items of $89 million for Depreciation and Amortization, $41 million for Deferred Income Taxes and $24 million for Property 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 $39 million inflow from Accrued Taxes, Net that includes a third quarter 2010 income tax refund of $11 million as a result of a federal net income tax operating loss in 2009 that was carried back to 2007 and 2008. Items contributing to the n et income tax operating loss include bonus depreciation and the favorable impact of a change in tax accounting method related to units of property. The $108 million outflow from Fuel Over/Under-Recovery, Net was the result of higher fuel costs in relation to commission-approved fuel recovery rates.
Net Cash Flows from Operating Activities were $233 million in 2009. PSO produced Net Income of $74 million during the period and had a noncash expense item of $84 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 capitalprimarily relates to a number of items. The $86 million inflow from Accounts Receivable, Net washad a $62 million inflow primarily due to receiving the SIA refund from the AEP East companiesdecreased sales to affiliates and lower customer receivables. The $46settlement of allowance sales to affiliated companies. Fuel, Materials and Supplies had a $57 million inflow fromprimarily due to a decrease in coal inventory deliveries. Accrued Taxes, Net was the resulthad a $30 million outflow due to temporary timing differences of increased accrualspayments for property taxes partially offset by a decrease of federal income tax related to property and income taxes.accruals. The $38 million outflow from Accounts Payablechange in Fuel Over/Under-Recovery, Net reflects the deferral of fuel costs as a fuel clause was primarily due to decreasesreactivated in customer accounts factored, fuel and purchased power payables.2009 under OPCo’s ESP.
Investing Activities
Net Cash Flows Used for Investing Activities during 2010 and 2009 were $90$11 million and $143 million, respectively.in 2011. Construction Expenditures of $153$50 million and $135 million in 2010 and 2009, respectively, were primarily related to project improvements made during the restoration of damage from a 2010 ice storm andenvironmental upgrades, as well as projects to improve service reliability for improved generation, transmission and distribution service. During 2010, PSO had a netdistribution. Environmental includes FGD project upgrades at various plants and landfill improvements. This decrease was partially offset by $23 million in Proceeds from Sales of $63Assets and an $18 million decrease in loans to the Utility Money Pool. During 2009, PSO
Net Cash Flows Used for Investing Activities were $258 million in 2010. OPCo had a net increase of $8 million in loans to the Utility Money Pool.
Pool of $179 million as well as Construction Expenditures of $78 million. The Construction Expenditures primarily related to environmental upgrades, as well as projects to improve service reliability for transmission and distribution. Environmental upgrades include FGD projects at the Amos Plant.
Financing Activities
Net Cash Flows Used for Financing Activities were $17$218 million during 2010. PSOin 2011. OPCo retired $165 million of Pollution Control Bonds in March 2011. In addition, OPCo paid $38$100 million inof dividends on common stock. This outflow wasThese decreases were partially offset by a net increasethe issuance of $23$50 million of Pollution Control Bonds in borrowings from the Utility Money Pool.March 2011.
Net Cash Flows Used forfrom Financing Activities were $90$6 million during 2009. PSO had a net decrease of $70 million in borrowings from the Utility Money Pool. PSO retired $50 million of Senior Unsecured Notes and2010. OPCo issued $34$86 million of Pollution Control Bonds. PSO paid $22Bonds in March 2010. This increase was partially offset by the payment of $75 million inof dividends on common stock. In addition, PSO received a capital contribution from Parent of $20 million.
Long-term debt issuances and retirements during the first ninethree months of 20102011 were:
Issuances | | | | | | | | |
| | | Principal | | Interest | | Due |
| Type of Debt | | Amount | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| Notes Payable | | $ | 1,750 | | 3.00 | | 2025 |
Issuances | | | | | | | | |
| | | Principal | | Interest | | Due |
| Type of Debt | | Amount | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| Pollution Control Bonds | | $ | 50,000 | (a) | Variable | | 2014 |
Retirements | (a) | | | | | | | |
| | | | | | | | |
None | | | | | | | | These pollution control bonds are subject to redemption earlier than the maturity date. Consequently, this bond has been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on OPCo’s Condensed Consolidated Balance Sheets. |
SUMMARYRetirements | | | | | | | |
| | | Principal | | Interest | | Due |
| Type of Debt | | Amount Paid | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| Pollution Control Bonds | | $ | 65,000 | | Variable | | 2036 |
| Pollution Control Bonds | | | 50,000 | | Variable | | 2014 |
| Pollution Control Bonds | | | 50,000 | | Variable | | 2014 |
CONTRACTUAL OBLIGATION INFORMATION
A summary of contractual obligations is included in the 20092010 Annual Report and has not changed significantly from year-end other than debt issuances and retirements discussed in the “Cash Flow” section above.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 2010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.
See the “Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 201 for a discussion of accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See “Quantitative And Qualitative Disclosures About Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 201 for a discussion of market risk.
OHIO POWER COMPANY CONSOLIDATED | |
CONDENSED CONSOLIDATED STATEMENTS OF INCOME | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| | | | | | |
| | 2011 | | | 2010 | |
REVENUES | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 626,806 | | | $ | 543,700 | |
Sales to AEP Affiliates | | | 225,049 | | | | 306,768 | |
Other Revenues – Affiliated | | | 7,018 | | | | 6,574 | |
Other Revenues – Nonaffiliated | | | 3,955 | | | | 4,231 | |
TOTAL REVENUES | | | 862,828 | | | | 861,273 | |
| | | | | | | | |
EXPENSES | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 294,483 | | | | 331,017 | |
Purchased Electricity for Resale | | | 44,897 | | | | 38,890 | |
Purchased Electricity from AEP Affiliates | | | 27,694 | | | | 22,191 | |
Other Operation | | | 99,718 | | | | 89,156 | |
Maintenance | | | 64,312 | | | | 56,231 | |
Depreciation and Amortization | | | 91,986 | | | | 89,361 | |
Taxes Other Than Income Taxes | | | 55,161 | | | | 53,084 | |
TOTAL EXPENSES | | | 678,251 | | | | 679,930 | |
| | | | | | | | |
OPERATING INCOME | | | 184,577 | | | | 181,343 | |
| | | | | | | | |
Other Income (Expense): | | | | | | | | |
Interest Income | | | 291 | | | | 405 | |
Carrying Costs Income | | | 7,077 | | | | 4,874 | |
Allowance for Equity Funds Used During Construction | | | 432 | | | | 1,031 | |
Interest Expense | | | (37,272 | ) | | | (39,975 | ) |
| | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 155,105 | | | | 147,678 | |
| | | | | | | | |
Income Tax Expense | | | 54,693 | | | | 55,775 | |
| | | | | | | | |
NET INCOME | | | 100,412 | | | | 91,903 | |
| | | | | | | | |
Less: Preferred Stock Dividend Requirements | | | 183 | | | | 183 | |
| | | | | | | | |
EARNINGS ATTRIBUTABLE TO COMMON STOCK | | $ | 100,229 | | | $ | 91,720 | |
| | | | | | | | |
The common stock of OPCo is wholly-owned by AEP. | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
OHIO POWER COMPANY CONSOLIDATED | |
CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S | |
EQUITY AND COMPREHENSIVE INCOME (LOSS) | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | | | | | |
| | | | | | | | | | | Accumulated | | | | |
| | | | | | | | | | | Other | | | | |
| | Common | | | Paid-in | | | Retained | | | Comprehensive | | | | |
| | Stock | | | Capital | | | Earnings | | | Income (Loss) | | | Total | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2009 | | $ | 321,201 | | | $ | 1,123,149 | | | $ | 1,908,803 | | | $ | (118,458 | ) | | $ | 3,234,695 | |
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (75,287 | ) | | | | | | | (75,287 | ) |
Preferred Stock Dividends | | | | | | | | | | | (183 | ) | | | | | | | (183 | ) |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 3,159,225 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income (Loss), | | | | | | | | | | | | | | | | | | | | |
Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $817 | | | | | | | | | | | | | | | (1,517 | ) | | | (1,517 | ) |
Amortization of Pension and OPEB Deferred Costs, | | | | | | | | | | | | | | | | | | | | |
Net of Tax of $949 | | | | | | | | | | | | | | | 1,762 | | | | 1,762 | |
NET INCOME | | | | | | | | | | | 91,903 | | | | | | | | 91,903 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 92,148 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – MARCH 31, 2010 | | $ | 321,201 | | | $ | 1,123,149 | | | $ | 1,925,236 | | | $ | (118,213 | ) | | $ | 3,251,373 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2010 | | $ | 321,201 | | | $ | 1,123,153 | | | $ | 1,852,889 | | | $ | (128,819 | ) | | $ | 3,168,424 | |
| | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (100,000 | ) | | | | | | | (100,000 | ) |
Preferred Stock Dividends | | | | | | | | | | | (183 | ) | | | | | | | (183 | ) |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 3,068,241 | |
| | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, | | | | | | | | | | | | | | | | | | | | |
Net of Taxes: | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $43 | | | | | | | | | | | | | | | 80 | | | | 80 | |
Amortization of Pension and OPEB Deferred Costs, | | | | | | | | | | | | | | | | | | | | |
Net of Tax of $1,078 | | | | | | | | | | | | | | | 2,002 | | | | 2,002 | |
NET INCOME | | | | | | | | | | | 100,412 | | | | | | | | 100,412 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 102,494 | |
| | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | |
EQUITY – MARCH 31, 2011 | | $ | 321,201 | | | $ | 1,123,153 | | | $ | 1,853,118 | | | $ | (126,737 | ) | | $ | 3,170,735 | |
| | | | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
OHIO POWER COMPANY CONSOLIDATED | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
ASSETS | |
March 31, 2011 and December 31, 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 1,204 | | | $ | 440 | |
Advances to Affiliates | | | 82,684 | | | | 100,500 | |
Accounts Receivable: | | | | | | | | |
Customers | | | 83,643 | | | | 86,186 | |
Affiliated Companies | | | 158,008 | | | | 198,845 | |
Accrued Unbilled Revenues | | | 27,402 | | | | 27,928 | |
Miscellaneous | | | 853 | | | | 2,368 | |
Allowance for Uncollectible Accounts | | | (2,181 | ) | | | (2,184 | ) |
Total Accounts Receivable | | | 267,725 | | | | 313,143 | |
Fuel | | | 217,945 | | | | 257,289 | |
Materials and Supplies | | | 128,509 | | | | 134,181 | |
Risk Management Assets | | | 27,776 | | | | 30,773 | |
Accrued Tax Benefits | | | 13,781 | | | | 69,021 | |
Prepayments and Other Current Assets | | | 33,549 | | | | 33,998 | |
TOTAL CURRENT ASSETS | | | 773,173 | | | | 939,345 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Generation | | | 6,894,869 | | | | 6,890,110 | |
Transmission | | | 1,249,671 | | | | 1,234,677 | |
Distribution | | | 1,638,926 | | | | 1,626,390 | |
Other Property, Plant and Equipment | | | 359,626 | | | | 359,254 | |
Construction Work in Progress | | | 143,808 | | | | 153,110 | |
Total Property, Plant and Equipment | | | 10,286,900 | | | | 10,263,541 | |
Accumulated Depreciation and Amortization | | | 3,690,781 | | | | 3,606,777 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 6,596,119 | | | | 6,656,764 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 959,912 | | | | 934,011 | |
Long-term Risk Management Assets | | | 29,384 | | | | 28,012 | |
Deferred Charges and Other Noncurrent Assets | | | 163,024 | | | | 189,195 | |
TOTAL OTHER NONCURRENT ASSETS | | | 1,152,320 | | | | 1,151,218 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 8,521,612 | | | $ | 8,747,327 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
OHIO POWER COMPANY CONSOLIDATED | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
LIABILITIES AND SHAREHOLDERS' EQUITY | |
March 31, 2011 and December 31, 2010 | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
| | (in thousands) | |
CURRENT LIABILITIES | | | | | | |
Accounts Payable: | | | | | | |
General | | $ | 143,376 | | | $ | 170,240 | |
Affiliated Companies | | | 108,344 | | | | 136,215 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 50,000 | | | | 165,000 | |
Risk Management Liabilities | | | 17,431 | | | | 22,166 | |
Customer Deposits | | | 23,996 | | | | 28,228 | |
Accrued Taxes | | | 190,471 | | | | 229,253 | |
Accrued Interest | | | 45,089 | | | | 46,184 | |
Other Current Liabilities | | | 93,953 | | | | 98,687 | |
TOTAL CURRENT LIABILITIES | | | 672,660 | | | | 895,973 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 2,364,651 | | | | 2,364,522 | |
Long-term Debt – Affiliated | | | 200,000 | | | | 200,000 | |
Long-term Risk Management Liabilities | | | 10,149 | | | | 8,403 | |
Deferred Income Taxes | | | 1,522,242 | | | | 1,531,639 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 129,893 | | | | 126,403 | |
Employee Benefits and Pension Obligations | | | 243,759 | | | | 246,517 | |
Deferred Credits and Other Noncurrent Liabilities | | | 190,907 | | | | 188,830 | |
TOTAL NONCURRENT LIABILITIES | | | 4,661,601 | | | | 4,666,314 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 5,334,261 | | | | 5,562,287 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 16,616 | | | | 16,616 | |
| | | | | | | | |
Rate Matters (Note 2) | | | | | | | | |
Commitments and Contingencies (Note 3) | | | | | | | | |
| | | | | | | | |
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 | | | 1,123,153 | | | | 1,123,153 | |
Retained Earnings | | | 1,853,118 | | | | 1,852,889 | |
Accumulated Other Comprehensive Income (Loss) | | | (126,737 | ) | | | (128,819 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | | 3,170,735 | | | | 3,168,424 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | | $ | 8,521,612 | | | $ | 8,747,327 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
OHIO POWER COMPANY CONSOLIDATED | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 100,412 | | | $ | 91,903 | |
Adjustments to Reconcile Net Income to Net Cash Flows from | | | | | | | | |
Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 91,986 | | | | 89,361 | |
Deferred Income Taxes | | | 29,038 | | | | 41,462 | |
Carrying Costs Income | | | (7,077 | ) | | | (4,874 | ) |
Allowance for Equity Funds Used During Construction | | | (432 | ) | | | (1,031 | ) |
Mark-to-Market of Risk Management Contracts | | | (818 | ) | | | (13,704 | ) |
Property Taxes | | | 24,950 | | | | 24,242 | |
Fuel Over/Under-Recovery, Net | | | (16,306 | ) | | | (38,025 | ) |
Change in Other Noncurrent Assets | | | (11,927 | ) | | | (5,008 | ) |
Change in Other Noncurrent Liabilities | | | 11,271 | | | | (1,741 | ) |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 45,418 | | | | 62,075 | |
Fuel, Materials and Supplies | | | 45,016 | | | | 57,032 | |
Accounts Payable | | | (51,223 | ) | | | (10,190 | ) |
Customer Deposits | | | (4,232 | ) | | | 829 | |
Accrued Taxes, Net | | | (22,818 | ) | | | (30,082 | ) |
Accrued Interest | | | (1,095 | ) | | | 2,243 | |
Other Current Assets | | | 480 | | | | (8,331 | ) |
Other Current Liabilities | | | (3,303 | ) | | | (4,837 | ) |
Net Cash Flows from Operating Activities | | | 229,340 | | | | 251,324 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (50,248 | ) | | | (78,398 | ) |
Change in Advances to Affiliates, Net | | | 17,816 | | | | (178,947 | ) |
Acquisitions of Assets | | | (1,288 | ) | | | (823 | ) |
Proceeds from Sales of Assets | | | 22,843 | | | | 2,047 | |
Other Investing Activities | | | - | | | | (2,184 | ) |
Net Cash Flows Used for Investing Activities | | | (10,877 | ) | | | (258,305 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Long-term Debt – Nonaffiliated | | | 49,917 | | | | 85,487 | |
Retirement of Long-term Debt – Nonaffiliated | | | (165,000 | ) | | | - | |
Principal Payments for Capital Lease Obligations | | | (2,271 | ) | | | (2,101 | ) |
Dividends Paid on Common Stock | | | (100,000 | ) | | | (75,287 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (183 | ) | | | (183 | ) |
Other Financing Activities | | | (162 | ) | | | (1,766 | ) |
Net Cash Flows from (Used for) Financing Activities | | | (217,699 | ) | | | 6,150 | |
| | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 764 | | | | (831 | ) |
Cash and Cash Equivalents at Beginning of Period | | | 440 | | | | 1,984 | |
Cash and Cash Equivalents at End of Period | | $ | 1,204 | | | $ | 1,153 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 36,936 | | | $ | 36,243 | |
Net Cash Paid for Income Taxes | | | 755 | | | | - | |
Noncash Acquisitions Under Capital Leases | | | 330 | | | | 22,559 | |
Construction Expenditures Included in Current Liabilities at March 31, | | | 15,559 | | | | 12,894 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
OHIO POWER COMPANY CONSOLIDATED
INDEX OF 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. The footnotes begin on page 143.
| Footnote Reference |
| |
Significant Accounting Matters | Note 1 |
| |
Rate Matters | Note 2 |
| |
Commitments, Guarantees and Contingencies | Note 3 |
| |
Benefit Plans | Note 5 |
| |
Business Segments | Note 6 |
| |
Derivatives and Hedging | Note 7 |
| |
Fair Value Measurements | Note 8 |
| |
Income Taxes | Note 9 |
| |
Financing Activities | Note 10 |
| |
Cost Reduction Initiatives | Note 11 |
PUBLIC SERVICE COMPANY OF OKLAHOMA
PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S DISCUSSION AND ANALYSIS
EXECUTIVE OVERVIEW
REGULATORY ACTIVITYLitigation and Environmental Issues
Oklahoma Regulatory Activity
In July 2010, PSO filed a request with the OCC to increase annual base rates by $82 million, including $30 million that is currently being recovered through a rider. The requested net annual increase to ratepayers would be $52 million. The requested increase includes a $24 million increase in depreciation and an 11.5% return on common equity. In October 2010, various parties, including the OCC staff, filed testimony regarding PSO’s requested base rate increase. These parties proposed that PSO's request to increase depreciation rates be denied and that existing depreciation rates continue. PSO’s request to move the $30 million currently recovered through a rider to base rates was not opposed. The parties’ net annual rate recommendations ranged from a rate reduction of $18 million to an increase of less than $1 million based on a recommended return on common equity range from 9.5% to 10%. A hearing is scheduled for December 2010. See “2010 Oklahoma Base Rate Case” section of Note 3.
LITIGATION AND ENVIRONMENTAL ISSUES
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 resolution will be or the timing and amount of any loss, fine or penalty may be. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss 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 20092010 Annual Report. Also, see Note 32 – Rate Matters and Note 43 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condensed Financial Statements beginning on page 161.143. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.
See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 230201 for additional discussion of relevant factors.
RESULTS OF OPERATIONS | | | | | |
| | | | | | | |
KWH Sales/Degree Days | | | | | |
| | | | | | |
Summary of KWH Energy Sales |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in millions of KWH) |
Retail: | | | | | |
| Residential | | 1,540 | | | 1,555 |
| Commercial | | 1,130 | | | 1,070 |
| Industrial | | 1,123 | | | 1,145 |
| Miscellaneous | | 279 | | | 269 |
Total Retail | | 4,072 | | | 4,039 |
| | | | | |
Wholesale | | 234 | | | 349 |
| | | | | |
Total KWHs | | 4,306 | | | 4,388 |
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.
Summary of Heating and Cooling Degree Days |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in degree days) |
| | | | | | |
Actual - Heating (a) | | 1,257 | | | 1,330 |
Normal - Heating (b) | | 1,058 | | | 1,047 |
| | | | | | |
Actual - Cooling (c) | | 33 | | | 8 |
Normal - Cooling (b) | | 13 | | | 13 |
| | | | | | |
(a) | 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) | Western Region cooling degree days are calculated on a 65 degree temperature base. |
First Quarter of 2011 Compared to First Quarter of 2010 |
| | | |
Reconciliation of First Quarter of 2010 to First Quarter of 2011 | |
Net Income | |
(in millions) | |
| | | |
First Quarter of 2010 | | $ | 4 | |
| | | | |
Changes in Gross Margin: | | | | |
Other Revenues | | | (2 | ) |
Total Change in Gross Margin | | | (2 | ) |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | 15 | |
Depreciation and Amortization | | | 3 | |
Interest Expense | | | 1 | |
Total Expenses and Other | | | 19 | |
| | | | |
Income Tax Expense | | | (6 | ) |
| | | | |
First Quarter of 2011 | | $ | 15 | |
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:
· | Other Revenues decreased $2 million primarily due to lower gains on the sale of emission allowances. |
Total Expenses and Other and Income Tax Expense changed between years as follows:
· | Other Operation and Maintenance expenses decreased $15 million primarily due to the following: |
| · | A $5 million decrease in maintenance of overhead lines primarily due to a decrease in vegetation management activities. |
| · | A $4 million decrease in plant maintenance expense resulting primarily from the 2011 deferral of generation maintenance expenses as a result of PSO’s base rate case. |
| · | A $2 million decrease in transmission expense primarily due to SPP formula rate adjustments. |
· | Depreciation and Amortization expenses decreased $3 million primarily due to a decrease in amortization of regulatory assets related to the Lawton settlement which was fully recovered in August 2010. |
· | Income Tax Expense increased $6 million primarily due to an increase in pretax book income. |
FINANCIAL CONDITION
LIQUIDITY
PSO participates in the Utility Money Pool, which provides access to AEP’s liquidity. PSO has $75 million of Senior Unsecured Notes that will mature in the second quarter of 2011. PSO relies upon ready access to capital markets, 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 beginning on page 201 for additional discussion of liquidity.
Credit Ratings
PSO’s ultimate access to capital markets may depend on its credit ratings. In addition, a credit rating downgrade of PSO by one of the rating agencies could increase PSO’s borrowing costs. Failure to maintain investment grade ratings may constrain PSO’s ability to participate in the Utility Money Pool or the amount of PSO’s receivables securitized by AEP Credit. Counterparty concerns about PSO’s credit quality could subject PSO to additional collateral demands under adequate assurance clauses under derivative and non-derivative energy contracts.
CASH FLOW
Cash flows for the three months ended March 31, 2011 and 2010 were as follows:
| | 2011 | | | 2010 | |
| | (in thousands) | |
Cash and Cash Equivalents at Beginning of Period | | $ | 470 | | | $ | 796 | |
Net Cash Flows from (Used for) Operating Activities | | | 98,230 | | | | (60,332 | ) |
Net Cash Flows from (Used for) Investing Activities | | | (35,602 | ) | | | 5,380 | |
Net Cash Flows from (Used for) Financing Activities | | | (62,344 | ) | | | 55,082 | |
Net Increase in Cash and Cash Equivalents | | | 284 | | | | 130 | |
Cash and Cash Equivalents at End of Period | | $ | 754 | | | $ | 926 | |
Operating Activities
Net Cash Flows from Operating Activities were $98 million in 2011. PSO produced Net Income of $15 million during the period and had noncash expense items of $24 million for Depreciation and Amortization and $15 million for Deferred Income Taxes, partially offset by a $28 million increase in the deferral of Property 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 $29 million inflow from Accounts Receivable, Net was primarily due to decreases in both affiliated and customer receivables. The $11 million inflow from Accrued Taxes, Net was the result of an increase in property tax accruals.
Net Cash Flows Used for Operating Activities were $60 million in 2010. PSO produced Net Income of $4 million during the period and had noncash expense items of $27 million for Depreciation and Amortization and $21 million for Deferred Income Taxes, partially offset by a $28 million increase in the deferral of Property 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 $15 million inflow from Accounts Payable primarily due to timing differences for payments to affiliates and payments of items accrued at December 31, 2009. The $82 million outflow from Fuel Over/Under-Recovery, Net was primarily due to refunding to customers the prior month’s fuel over-recoveries through lower fuel factors.
Investing Activities
Net Cash Flows Used for Investing Activities during 2011 was $36 million and Net Cash Flows from Investing Activities during 2010 was $5 million. Construction Expenditures of $33 million and $55 million in 2011 and 2010, respectively, were primarily related to projects for improved generation, transmission and distribution service reliability, customer service work and storm restoration. During 2010, PSO had a net decrease of $63 million in loans to the Utility Money Pool.
Financing Activities
Net Cash Flows Used for Financing Activities were $62 million during 2011. PSO issued $250 million of Senior Unsecured Notes, partially offset by the retirement of $200 million of Senior Unsecured Notes. PSO had a net decrease of $91 million in borrowings from the Utility Money Pool. In addition, PSO paid $16 million in common stock dividends.
Net Cash Flows from Financing Activities were $55 million during 2010. PSO had a net increase of $69 million in borrowings from the Utility Money Pool. This inflow was partially offset by $13 million paid in common stock dividends.
Long-term debt issuances and retirements during the first three months of 2011 were:
Issuances | | | | | | | | |
| | | Principal | | Interest | | Due |
| Type of Debt | | Amount | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| Senior Unsecured Notes | | $ | 250,000 | | 4.40 | | 2021 |
Retirements | | | | | | | | |
| | | Principal | | Interest | | Due |
| Type of Debt | | Amount Paid | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| Senior Unsecured Notes | | $ | 200,000 | | 6.00 | | 2032 |
CONTRACTUAL OBLIGATION INFORMATION
A summary of contractual obligations is included in the 2010 Annual Report and has not changed significantly from year-end other than debt issuances and retirements discussed in the “Cash Flow” section above.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 20092010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.
See the “New Accounting“Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230201 for a discussion of the adoption and impact of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK MANAGEMENT ACTIVITIES
See “Quantitative And Qualitative Disclosures About Risk Management Activities”Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230201 for a discussion of risk management activities.market risk.
PUBLIC SERVICE COMPANY OF OKLAHOMA | PUBLIC SERVICE COMPANY OF OKLAHOMA | | PUBLIC SERVICE COMPANY OF OKLAHOMA | |
CONDENSED STATEMENTS OF INCOME | CONDENSED STATEMENTS OF INCOME | | CONDENSED STATEMENTS OF INCOME | |
For the Three and Nine Months Ended September 30, 2010 and 2009 | | |
For the Three Months Ended March 31, 2011 and 2010 | | For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | (in thousands) | | (in thousands) | |
(Unaudited) | (Unaudited) | | (Unaudited) | |
| | | | | | | | | | | | | |
| | Three Months Ended | | | Nine Months Ended | | | | | | | |
| | 2010 | | | 2009 | | | 2010 | | | 2009 | | | 2011 | | | 2010 | |
REVENUES | | | | | | | | | | | | | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 420,877 | | | $ | 311,274 | | | $ | 971,822 | | | $ | 853,808 | | | $ | 284,587 | | | $ | 228,551 | |
Sales to AEP Affiliates | | | 4,665 | | | | 6,668 | | | | 17,816 | | | | 34,181 | | | | 2,796 | | | | 8,670 | |
Other Revenues | | | 1,027 | | | | 613 | | | | 2,372 | | | | 2,994 | | | | 620 | | | | 534 | |
TOTAL REVENUES | | | 426,569 | | | | 318,555 | | | | 992,010 | | | | 890,983 | | | | 288,003 | | | | 237,755 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
EXPENSES | | | | | | | | | | | | | | | | | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 140,367 | | | | 79,610 | | | | 269,954 | | | | 261,762 | | | | 91,748 | | | | 40,972 | |
Purchased Electricity for Resale | | | 50,691 | | | | 42,090 | | | | 149,226 | | | | 132,623 | | | | 41,179 | | | | 44,980 | |
Purchased Electricity from AEP Affiliates | | | 17,458 | | | | 5,424 | | | | 38,921 | | | | 14,755 | | | | 16,611 | | | | 10,992 | |
Other Operation | | | 50,575 | | | | 48,145 | | | | 171,074 | | | | 134,211 | | | | 44,404 | | | | 49,662 | |
Maintenance | | | 25,867 | | | | 24,601 | | | | 83,844 | | | | 77,996 | | | | 20,721 | | | | 30,939 | |
Depreciation and Amortization | | | 26,703 | | | | 27,799 | | | | 80,911 | | | | 84,278 | | | | 23,863 | | | | 27,288 | |
Taxes Other Than Income Taxes | | | 10,254 | | | | 9,534 | | | | 31,539 | | | | 31,243 | | | | 10,596 | | | | 10,300 | |
TOTAL EXPENSES | | | 321,915 | | | | 237,203 | | | | 825,469 | | | | 736,868 | | | | 249,122 | | | | 215,133 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 104,654 | | | | 81,352 | | | | 166,541 | | | | 154,115 | | | | 38,881 | | | | 22,622 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | | | | |
Interest Income | | | 27 | | | | 342 | | | | 302 | | | | 1,570 | | | | 52 | | | | 182 | |
Carrying Costs Income | | | 763 | | | | 986 | | | | 2,449 | | | | 3,716 | | | | 647 | | | | 867 | |
Allowance for Equity Funds Used During Construction | | | 21 | | | | 483 | | | | 387 | | | | 1,224 | | | | 366 | | | | 247 | |
Interest Expense | | | (15,759 | ) | | | (13,884 | ) | | | (48,887 | ) | | | (43,852 | ) | | | (15,938 | ) | | | (17,363 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE | | | 89,706 | | | | 69,279 | | | | 120,792 | | | | 116,773 | | | | 24,008 | | | | 6,555 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Income Tax Expense | | | 34,274 | | | | 25,702 | | | | 45,732 | | | | 43,036 | | | | 8,619 | | | | 2,416 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
NET INCOME | | | 55,432 | | | | 43,577 | | | | 75,060 | | | | 73,737 | | | | 15,389 | | | | 4,139 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Preferred Stock Dividend Requirements | | | 48 | | | | 53 | | | | 151 | | | | 159 | | | | 49 | | | | 53 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
EARNINGS ATTRIBUTABLE TO COMMON STOCK | | $ | 55,384 | | | $ | 43,524 | | | $ | 74,909 | | | $ | 73,578 | | | $ | 15,340 | | | $ | 4,086 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
The common stock of PSO is wholly-owned by AEP. | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | | See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
PUBLIC SERVICE COMPANY OF OKLAHOMA | PUBLIC SERVICE COMPANY OF OKLAHOMA | | PUBLIC SERVICE COMPANY OF OKLAHOMA | |
CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S | CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S | | CONDENSED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S | |
EQUITY AND COMPREHENSIVE INCOME (LOSS) | EQUITY AND COMPREHENSIVE INCOME (LOSS) | | EQUITY AND COMPREHENSIVE INCOME (LOSS) | |
For the Nine Months Ended September 30, 2010 and 2009 | | |
For the Three Months Ended March 31, 2011 and 2010 | | For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | (in thousands) | | (in thousands) | |
(Unaudited) | (Unaudited) | | (Unaudited) | |
| | | | |
| | | | | | | | | | | Accumulated | | | | | | | | | | | | | | | Accumulated | | | | |
| | | | | | | | | | | Other | | | | | | | | | | | | | | | Other | | | | |
| | Common | | | Paid-in | | | Retained | | | Comprehensive | | | | | | Common | | | Paid-in | | | Retained | | | Comprehensive | | | | |
| | Stock | | | Capital | | | Earnings | | | Income (Loss) | | | Total | | | Stock | | | Capital | | | Earnings | | | Income (Loss) | | | Total | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2008 | | $ | 157,230 | | | $ | 340,016 | | | $ | 251,704 | | | $ | (704 | ) | | $ | 748,246 | | |
EQUITY – DECEMBER 31, 2009 | | | $ | 157,230 | | | $ | 364,231 | | | $ | 290,880 | | | $ | (599 | ) | | $ | 811,742 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Capital Contribution from Parent | | | | | | | 20,000 | | | | | | | | | | | | 20,000 | | |
Common Stock Dividends | | | | | | | | | | | (21,750 | ) | | | | | | | (21,750 | ) | | | | | | | | | | | (12,687 | ) | | | | | | | (12,687 | ) |
Preferred Stock Dividends | | | | | | | | | | | (159 | ) | | | | | | | (159 | ) | | | | | | | | | | | (53 | ) | | | | | | | (53 | ) |
Gain on Reacquired Preferred Stock | | | | | | | 1 | | | | | | | | | | | | 1 | | |
Other Changes in Common Shareholder's | | | | | | | | | | | | | | | | | | | | | |
Equity | | | | | | | 4,214 | | | | (4,214 | ) | | | | | | | - | | |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | | 799,002 | |
| | | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $62 | | | | | | | | | | | | | | | | 116 | | | | 116 | |
NET INCOME | | | | | | | | | | | | 4,139 | | | | | | | | 4,139 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | 4,255 | |
| | | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | |
EQUITY – MARCH 31, 2010 | | | $ | 157,230 | | | $ | 364,231 | | | $ | 282,279 | | | $ | (483 | ) | | $ | 803,257 | |
| | | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2010 | | | $ | 157,230 | | | $ | 364,307 | | | $ | 312,441 | | | $ | 8,494 | | | $ | 842,472 | |
| | | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | | (16,250 | ) | | | | | | | (16,250 | ) |
Preferred Stock Dividends | | | | | | | | | | | | (49 | ) | | | | | | | (49 | ) |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 746,338 | | | | | | | | | | | | | | | | | | | | 826,173 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Loss, Net of Taxes: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $78 | | | | | | | | | | | | | | | (145 | ) | | | (145 | ) | |
Cash Flow Hedges, Net of Tax of $239 | | | | | | | | | | | | | | | | (443 | ) | | | (443 | ) |
NET INCOME | | | | | | | | | | | 73,737 | | | | | | | | 73,737 | | | | | | | | | | | | 15,389 | | | | | | | | 15,389 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 73,592 | | | | | | | | | | | | | | | | | | | | 14,946 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
EQUITY – SEPTEMBER 30, 2009 | | $ | 157,230 | | | $ | 364,231 | | | $ | 299,318 | | | $ | (849 | ) | | $ | 819,930 | | |
EQUITY – MARCH 31, 2011 | | | $ | 157,230 | | | $ | 364,307 | | | $ | 311,531 | | | $ | 8,051 | | | $ | 841,119 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | |
EQUITY – DECEMBER 31, 2009 | | $ | 157,230 | | | $ | 364,231 | | | $ | 290,880 | | | $ | (599 | ) | | $ | 811,742 | | |
| | | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends | | | | | | | | | | | (38,026 | ) | | | | | | | (38,026 | ) | |
Preferred Stock Dividends | | | | | | | | | | | (151 | ) | | | | | | | (151 | ) | |
Gain on Reacquired Preferred Stock | | | | | | | 76 | | | | | | | | | | | | 76 | | |
SUBTOTAL – COMMON | | | | | | | | | | | | | | | | | | | | | |
SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | | | | | 773,641 | | |
| | | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | | | | |
Cash Flow Hedges, Net of Tax of $97 | | | | | | | | | | | | | | | 181 | | | | 181 | | |
NET INCOME | | | | | | | | | | | 75,060 | | | | | | | | 75,060 | | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | 75,241 | | |
| | | | | | | | | | | | | | | | | | | | | |
TOTAL COMMON SHAREHOLDER'S | | | | | | | | | | | | | | | | | | | | | |
EQUITY – SEPTEMBER 30, 2010 | | $ | 157,230 | | | $ | 364,307 | | | $ | 327,763 | | | $ | (418 | ) | | $ | 848,882 | | |
| | | | | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page161. | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | | See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
PUBLIC SERVICE COMPANY OF OKLAHOMA |
CONDENSED BALANCE SHEETS |
ASSETS |
September 30, 2010 and December 31, 2009 |
(in thousands) |
(Unaudited) |
|
| | 2010 | | 2009 |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 1,587 | | $ | 796 |
Advances to Affiliates | | | - | | | 62,695 |
Accounts Receivable: | | | | | | |
| Customers | | | 31,750 | | | 38,239 |
| Affiliated Companies | | | 66,928 | | | 59,096 |
| Miscellaneous | | | 5,900 | | | 7,242 |
| Allowance for Uncollectible Accounts | | | (143) | | | (304) |
| | Total Accounts Receivable | | | 104,435 | | | 104,273 |
Fuel | | | 16,646 | | | 20,892 |
Materials and Supplies | | | 46,970 | | | 44,914 |
Risk Management Assets | | | 3,000 | | | 2,376 |
Deferred Income Tax Benefits | | | 5,658 | | | 26,335 |
Accrued Tax Benefits | | | 7,059 | | | 15,291 |
Regulatory Asset for Under-Recovered Fuel Costs | | | 56,570 | | | - |
Prepayments and Other Current Assets | | | 9,560 | | | 9,139 |
TOTAL CURRENT ASSETS | | | 251,485 | | | 286,711 |
| | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | |
Electric: | | | | | | |
| Production | | | 1,321,952 | | | 1,300,069 |
| Transmission | | | 658,623 | | | 617,291 |
| Distribution | | | 1,670,406 | | | 1,596,355 |
Other Property, Plant and Equipment | | | 247,581 | | | 228,705 |
Construction Work in Progress | | | 43,893 | | | 67,138 |
Total Property, Plant and Equipment | | | 3,942,455 | | | 3,809,558 |
Accumulated Depreciation and Amortization | | | 1,253,107 | | | 1,220,177 |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 2,689,348 | | | 2,589,381 |
| | | | | | |
OTHER NONCURRENT ASSETS | | | | | | |
Regulatory Assets | | | 263,269 | | | 279,185 |
Long-term Risk Management Assets | | | 501 | | | 50 |
Deferred Charges and Other Noncurrent Assets | | | 23,110 | | | 13,880 |
TOTAL OTHER NONCURRENT ASSETS | | | 286,880 | | | 293,115 |
| | | | | | |
TOTAL ASSETS | | $ | 3,227,713 | | $ | 3,169,207 |
| | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. |
PUBLIC SERVICE COMPANY OF OKLAHOMA | |
CONDENSED BALANCE SHEETS | |
ASSETS | |
March 31, 2011 and December 31, 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 754 | | | $ | 470 | |
Advances to Affiliates | | | 3,093 | | | | - | |
Accounts Receivable: | | | | | | | | |
Customers | | | 35,810 | | | | 43,049 | |
Affiliated Companies | | | 42,858 | | | | 65,070 | |
Miscellaneous | | | 4,960 | | | | 5,497 | |
Allowance for Uncollectible Accounts | | | (433 | ) | | | (971 | ) |
Total Accounts Receivable | | | 83,195 | | | | 112,645 | |
Fuel | | | 20,678 | | | | 20,176 | |
Materials and Supplies | | | 46,410 | | | | 46,247 | |
Risk Management Assets | | | 680 | | | | 14,225 | |
Accrued Tax Benefits | | | 36,779 | | | | 38,589 | |
Regulatory Asset for Under-Recovered Fuel Costs | | | 31,399 | | | | 37,262 | |
Prepayments and Other Current Assets | | | 13,517 | | | | 9,416 | |
TOTAL CURRENT ASSETS | | | 236,505 | | | | 279,030 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Generation | | | 1,333,338 | | | | 1,330,368 | |
Transmission | | | 676,541 | | | | 663,994 | |
Distribution | | | 1,705,879 | | | | 1,686,470 | |
Other Property, Plant and Equipment | | | 236,883 | | | | 235,406 | |
Construction Work in Progress | | | 43,902 | | | | 59,091 | |
Total Property, Plant and Equipment | | | 3,996,543 | | | | 3,975,329 | |
Accumulated Depreciation and Amortization | | | 1,260,749 | | | | 1,255,064 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 2,735,794 | | | | 2,720,265 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 268,611 | | | | 263,545 | |
Long-term Risk Management Assets | | | 351 | | | | 252 | |
Deferred Charges and Other Noncurrent Assets | | | 44,211 | | | | 20,979 | |
TOTAL OTHER NONCURRENT ASSETS | | | 313,173 | | | | 284,776 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 3,285,472 | | | $ | 3,284,071 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| | | | | | |
| | | | | | |
| | | | | | |
PUBLIC SERVICE COMPANY OF OKLAHOMA | |
CONDENSED BALANCE SHEETS | |
LIABILITIES AND SHAREHOLDERS' EQUITY | |
March 31, 2011 and December 31, 2010 | |
(Unaudited) | |
| | | | | | |
| | 2011 | | | 2010 | |
| | (in thousands) | |
CURRENT LIABILITIES | | | | | | |
Advances from Affiliates | | $ | - | | | $ | 91,382 | |
Accounts Payable: | | | | | | | | |
General | | | 60,778 | | | | 69,155 | |
Affiliated Companies | | | 63,171 | | | | 53,179 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 75,116 | | | | 25,000 | |
Risk Management Liabilities | | | 1,193 | | | | 922 | |
Customer Deposits | | | 42,837 | | | | 41,217 | |
Accrued Taxes | | | 43,581 | | | | 25,390 | |
Accrued Interest | | | 17,094 | | | | 9,238 | |
Other Current Liabilities | | | 33,830 | | | | 38,095 | |
TOTAL CURRENT LIABILITIES | | | 337,600 | | | | 353,578 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 944,259 | | | | 946,186 | |
Long-term Risk Management Liabilities | | | 193 | | | | 197 | |
Deferred Income Taxes | | | 669,885 | | | | 660,783 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 343,277 | | | | 336,961 | |
Employee Benefits and Pension Obligations | | | 97,406 | | | | 98,107 | |
Deferred Credits and Other Noncurrent Liabilities | | | 46,851 | | | | 40,905 | |
TOTAL NONCURRENT LIABILITIES | | | 2,101,871 | | | | 2,083,139 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 2,439,471 | | | | 2,436,717 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 4,882 | | | | 4,882 | |
| | | | | | | | |
Rate Matters (Note 2) | | | | | | | | |
Commitments and Contingencies (Note 3) | | | | | | | | |
| | | | | | | | |
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 | | | 364,307 | | | | 364,307 | |
Retained Earnings | | | 311,531 | | | | 312,441 | |
Accumulated Other Comprehensive Income (Loss) | | | 8,051 | | | | 8,494 | |
TOTAL COMMON SHAREHOLDER’S EQUITY | | | 841,119 | | | | 842,472 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 3,285,472 | | | $ | 3,284,071 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
PUBLIC SERVICE COMPANY OF OKLAHOMA | |
CONDENSED BALANCE SHEETS | |
LIABILITIES AND SHAREHOLDERS' EQUITY | |
September 30, 2010 and December 31, 2009 | |
(Unaudited) | |
| | | | | | |
| | 2010 | | | 2009 | |
| | (in thousands) | |
CURRENT LIABILITIES | | | | | | |
Advances from Affiliates | | $ | 23,024 | | | $ | - | |
Accounts Payable: | | | | | | | | |
General | | | 68,411 | | | | 76,895 | |
Affiliated Companies | | | 79,357 | | | | 71,099 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 75,350 | | | | - | |
Risk Management Liabilities | | | 308 | | | | 2,579 | |
Customer Deposits | | | 40,740 | | | | 42,002 | |
Accrued Taxes | | | 49,468 | | | | 19,471 | |
Regulatory Liability for Over-Recovered Fuel Costs | | | - | | | | 51,087 | |
Other Current Liabilities | | | 54,587 | | | | 60,905 | |
TOTAL CURRENT LIABILITIES | | | 391,245 | | | | 324,038 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 895,293 | | | | 968,121 | |
Long-term Risk Management Liabilities | | | 119 | | | | 144 | |
Deferred Income Taxes | | | 618,378 | | | | 588,768 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 327,234 | | | | 326,931 | |
Employee Benefits and Pension Obligations | | | 97,893 | | | | 107,748 | |
Deferred Credits and Other Noncurrent Liabilities | | | 43,787 | | | | 36,457 | |
TOTAL NONCURRENT LIABILITIES | | | 1,982,704 | | | | 2,028,169 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 2,373,949 | | | | 2,352,207 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 4,882 | | | | 5,258 | |
| | | | | | | | |
Rate Matters (Note 3) | | | | | | | | |
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 | | | 364,307 | | | | 364,231 | |
Retained Earnings | | | 327,763 | | | | 290,880 | |
Accumulated Other Comprehensive Income (Loss) | | | (418 | ) | | | (599 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | | 848,882 | | | | 811,742 | |
| | | | | | | | |
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 3,227,713 | | | $ | 3,169,207 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | |
PUBLIC SERVICE COMPANY OF OKLAHOMA | |
CONDENSED STATEMENTS OF CASH FLOWS | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 15,389 | | | $ | 4,139 | |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating | | | | | | | | |
Activities: | | | | | | | | |
Depreciation and Amortization | | | 23,863 | | | | 27,288 | |
Deferred Income Taxes | | | 15,364 | | | | 20,526 | |
Carrying Costs Income | | | (647 | ) | | | (867 | ) |
Allowance for Equity Funds Used During Construction | | | (366 | ) | | | (247 | ) |
Mark-to-Market of Risk Management Contracts | | | 397 | | | | (2,959 | ) |
Property Taxes | | | (28,113 | ) | | | (27,797 | ) |
Fuel Over/Under-Recovery, Net | | | 5,863 | | | | (82,112 | ) |
Change in Other Noncurrent Assets | | | (770 | ) | | | (10,473 | ) |
Change in Other Noncurrent Liabilities | | | 20,617 | | | | 1,764 | |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 29,450 | | | | 5,626 | |
Fuel, Materials and Supplies | | | (665 | ) | | | (2,362 | ) |
Accounts Payable | | | 4,103 | | | | 15,235 | |
Accrued Taxes, Net | | | 11,392 | | | | 1,152 | |
Other Current Assets | | | (2,025 | ) | | | (2,108 | ) |
Other Current Liabilities | | | 4,378 | | | | (7,137 | ) |
Net Cash Flows from (Used for) Operating Activities | | | 98,230 | | | | (60,332 | ) |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (32,876 | ) | | | (54,837 | ) |
Change in Advances to Affiliates, Net | | | (3,093 | ) | | | 62,695 | |
Other Investing Activities | | | 367 | | | | (2,478 | ) |
Net Cash Flows from (Used for) Investing Activities | | | (35,602 | ) | | | 5,380 | |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Long-term Debt – Nonaffiliated | | | 246,376 | | | | - | |
Change in Advances from Affiliates, Net | | | (91,382 | ) | | | 68,743 | |
Retirement of Long-term Debt – Nonaffiliated | | | (200,000 | ) | | | - | |
Principal Payments for Capital Lease Obligations | | | (1,039 | ) | | | (1,026 | ) |
Dividends Paid on Common Stock | | | (16,250 | ) | | | (12,687 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (49 | ) | | | (53 | ) |
Other Financing Activities | | | - | | | | 105 | |
Net Cash Flows from (Used for) Financing Activities | | | (62,344 | ) | | | 55,082 | |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 284 | | | | 130 | |
Cash and Cash Equivalents at Beginning of Period | | | 470 | | | | 796 | |
Cash and Cash Equivalents at End of Period | | $ | 754 | | | $ | 926 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid (Received) for Interest, Net of Capitalized Amounts | | $ | (5,337 | ) | | $ | 8,267 | |
Net Cash Paid (Received) for Income Taxes | | | 286 | | | | (1,331 | ) |
Noncash Acquisitions Under Capital Leases | | | 384 | | | | 13,274 | |
Construction Expenditures Included in Current Liabilities at March 31, | | | 5,048 | | | | 28,799 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
PUBLIC SERVICE COMPANY OF OKLAHOMA |
CONDENSED STATEMENTS OF CASH FLOWS |
For the Nine Months Ended September 30, 2010 and 2009 |
(in thousands) |
(Unaudited) |
|
| | 2010 | | 2009 |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 75,060 | | $ | 73,737 |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | |
| | Depreciation and Amortization | | | 80,911 | | | 84,278 |
| | Deferred Income Taxes | | | 43,631 | | | 13,103 |
| | Carrying Costs Income | | | (2,449) | | | (3,716) |
| | Allowance for Equity Funds Used During Construction | | | (387) | | | (1,224) |
| | Mark-to-Market of Risk Management Contracts | | | (3,248) | | | 2,185 |
| | Property Taxes | | | (9,198) | | | (8,993) |
| | Fuel Over/Under-Recovery, Net | | | (107,657) | | | (14,566) |
| | Change in Other Noncurrent Assets | | | (11,319) | | | 8,040 |
| | Change in Other Noncurrent Liabilities | | | 6,110 | | | (2,768) |
| | Changes in Certain Components of Working Capital: | | | | | | |
| | | Accounts Receivable, Net | | | (162) | | | 86,010 |
| | | Fuel, Materials and Supplies | | | 2,190 | | | 4,199 |
| | | Accounts Payable | | | 6,421 | | | (38,023) |
| | | Accrued Taxes, Net | | | 38,830 | | | 46,119 |
| | | Other Current Assets | | | (494) | | | (3,822) |
| | | Other Current Liabilities | | | (10,554) | | | (11,800) |
Net Cash Flows from Operating Activities | | | 107,685 | | | 232,759 |
| | | | | | |
INVESTING ACTIVITIES | | | | | | |
Construction Expenditures | | | (152,589) | | | (134,756) |
Change in Advances to Affiliates, Net | | | 62,695 | | | (8,450) |
Other Investing Activities | | | (450) | | | 261 |
Net Cash Flows Used for Investing Activities | | | (90,344) | | | (142,945) |
| | | | | | |
FINANCING ACTIVITIES | | | | | | |
Capital Contribution from Parent | | | - | | | 20,000 |
Issuance of Long-term Debt – Nonaffiliated | | | 1,740 | | | 33,248 |
Change in Advances from Affiliates, Net | | | 23,024 | | | (70,308) |
Retirement of Long-term Debt – Nonaffiliated | | | - | | | (50,000) |
Retirement of Cumulative Preferred Stock | | | (300) | | | (2) |
Principal Payments for Capital Lease Obligations | | | (3,025) | | | (1,128) |
Dividends Paid on Common Stock | | | (38,026) | | | (21,750) |
Dividends Paid on Cumulative Preferred Stock | | | (151) | | | (159) |
Other Financing Activities | | | 188 | | | 247 |
Net Cash Flows Used For Financing Activities | | | (16,550) | | | (89,852) |
| | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | 791 | | | (38) |
Cash and Cash Equivalents at Beginning of Period | | | 796 | | | 1,345 |
Cash and Cash Equivalents at End of Period | | $ | 1,587 | | $ | 1,307 |
| | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 37,915 | | $ | 55,152 |
Net Cash Paid (Received) for Income Taxes | | | (18,520) | | | 4,423 |
Noncash Acquisitions Under Capital Leases | | | 13,572 | | | 2,802 |
Construction Expenditures Included in Accounts Payable at September 30, | | | 5,254 | | | 7,315 |
| | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
INDEX TOOF 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. The footnotes begin on page 161.143.
| Footnote Reference |
| |
Significant Accounting Matters | Note 1 |
New Accounting Pronouncements and Extraordinary Item | Note 2 |
Rate Matters | Note 32 |
| |
Commitments, Guarantees and Contingencies | Note 43 |
| |
Benefit Plans | Note 65 |
| |
Business Segments | Note 76 |
| |
Derivatives and Hedging | Note 87 |
| |
Fair Value Measurements | Note 98 |
| |
Income Taxes | Note 109 |
| |
Financing Activities | Note 1110 |
| |
Cost Reduction Initiatives | Note 1211 |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | |
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS | |
| | | |
RESULTS OF OPERATIONS | | | |
| | | |
Third Quarter of 2010 Compared to Third Quarter of 2009 | |
| | | |
Reconciliation of Third Quarter of 2009 to Third Quarter of 2010 | |
Income Before Extraordinary Loss | |
(in millions) | |
| | | |
Third Quarter of 2009 | | $ | 65 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins (a) | | | 49 | |
Transmission Revenues | | | (1 | ) |
Other Revenues | | | (11 | ) |
Total Change in Gross Margin | | | 37 | |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | 5 | |
Depreciation and Amortization | | | 5 | |
Taxes Other Than Income Taxes | | | (1 | ) |
Other Income | | | (5 | ) |
Interest Expense | | | (7 | ) |
Equity Earnings of Unconsolidated Subsidiaries | | | 1 | |
Total Expenses and Other | | | (2 | ) |
| | | | |
Income Tax Expense | | | (18 | ) |
| | | | |
Third Quarter of 2010 | | $ | 82 | |
| | | | |
(a)Includes firm wholesale sales to municipals and cooperatives. | |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
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 $49 million primarily due to:
|
| | · | An $18 million increase in base rates in Arkansas and Texas. |
| | · | A $16 million increase in weather-related usage primarily due to a 35% increase in cooling degree days. |
| | · | A $6 million increase in fuel recovery primarily due to lower capacity costs and increased wholesale fuel recovery. |
| | · | A $5 million increase in industrial sales due to higher demand. |
| · | Other Revenues decreased $11 million resulting from the deconsolidation of SWEPCo’s mining subsidiary, DHLC. Prior to the deconsolidation, SWEPCo recorded revenues from coal deliveries from DHLC to CLECO. SWEPCo prospectively adopted the “Consolidation” accounting guidance effective January 1, 2010 and began accounting for DHLC under the equity method of accounting. The decreased revenue from coal deliveries was partially offset by a corresponding decrease in Other Operation and Maintenance expenses from mining operations as discussed below.
|
Total Expenses and Other and Income Tax Expense changed between years as follows:
| · | Other Operation and Maintenance expenses decreased $5 million primarily due to:
|
| | · | An $11 million decrease in expenses for coal deliveries from SWEPCo’s mining subsidiary, DHLC. The decreased expenses for coal deliveries were offset by a corresponding decrease in revenues from mining operations as discussed above. |
| | This decrease was partially offset by: |
| | · | A $7 million increase in distribution maintenance resulting primarily from storm-related amortization expense. |
| · | Depreciation and Amortization expenses decreased $5 million primarily due to lower Arkansas and Texas depreciation resulting from the Arkansas and Texas base rate orders and the deconsolidation of DHLC, partially offset by plant additions including the Stall Unit.
|
| · | Other Income decreased $5 million primarily due to a decrease in the equity component of AFUDC as a result of the completion of the Stall Unit construction project in June 2010.
|
| · | Interest Expense increased $7 million primarily due to increased long-term debt outstanding.
|
| · | Income Tax Expense increased $18 million primarily due to an increase in pretax book income and other book/tax differences accounted for on a flow-through basis.
|
Nine Months Ended September 30, 2010 Compared to Nine Months Ended September 30, 2009 |
| | | | |
Reconciliation of Nine Months Ended September 30, 2009 to Nine Months Ended September 30, 2010 |
Income Before Extraordinary Loss |
(in millions) |
| | | | |
Nine Months Ended September 30, 2009 | | $ | 113 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins (a) | | | 91 | |
Off-system Sales | | | 1 | |
Transmission Revenues | | | 1 | |
Other Revenues | | | (29) | |
Total Change in Gross Margin | | | 64 | |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | (17) | |
Depreciation and Amortization | | | 14 | |
Taxes Other Than Income Taxes | | | (2) | |
Other Income | | | 3 | |
Interest Expense | | | (12) | |
Equity Earnings of Unconsolidated Subsidiaries | | | 2 | |
Total Expenses and Other | | | (12) | |
| | | | |
Income Tax Expense | | | (26) | |
| | | | |
Nine Months Ended September 30, 2010 | | $ | 139 | |
| | | | |
(a) Includes firm wholesale sales to municipals and cooperatives. |
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 $91 million primarily due to:
|
| | · | A $32 million increase in weather-related usage primarily due to a 42% increase in heating degree days and a 30% increase in cooling degree days. |
| | · | A $31 million increase in base rates in Arkansas and Texas. |
| | · | An $11 million increase in fuel recovery primarily due to lower capacity costs and increased wholesale fuel recovery. |
| | · | An $11 million increase in industrial sales due to higher demand. |
| · | Other Revenues decreased $29 million resulting from the deconsolidation of SWEPCo’s mining subsidiary, DHLC. Prior to the deconsolidation, SWEPCo recorded revenues from coal deliveries from DHLC to CLECO. SWEPCo prospectively adopted the “Consolidation” accounting guidance effective January 1, 2010 and began accounting for DHLC under the equity method of accounting. The decreased revenue from coal deliveries was partially offset by a corresponding decrease in Other Operation and Maintenance expenses from mining operations as discussed below.
|
Total Expenses and Other and Income Tax Expense changed between years as follows:
| · | Other Operation and Maintenance expenses increased $17 million primarily due to:
|
| | · | A $28 million increase due to expenses related to the cost reduction initiatives. |
| | · | A $5 million increase in other generation operation expenses primarily related to Stall Unit testing for commercial operation. The Stall Unit was placed in service in June 2010. |
| | · | A $4 million increase in employee-related expenses. |
| | · | A $2 million gain on sale of property during the first quarter of 2009 related to the sale of percentage ownership of Turk Plant to nonaffiliated companies who exercised their participation options. |
| | These increases were partially offset by: |
| | · | A $24 million decrease in expenses for coal deliveries from SWEPCo’s mining subsidiary, DHLC. The decreased expenses for coal deliveries were partially offset by a corresponding decrease in revenues from mining operations as discussed above. |
| · | Depreciation and Amortization expenses decreased $14 million primarily due to lower Arkansas and Texas depreciation resulting from the Arkansas and Texas base rate orders and the deconsolidation of DHLC, partially offset by plant additions including the Stall Unit.
|
| · | Other Income increased $3 million primarily due to an increase in the equity component of AFUDC as a result of construction at the Turk Plant and Stall Unit and the reapplication of “Regulated Operations” accounting guidance for the generation portion of Texas’ retail jurisdiction effective the second quarter of 2009. This increase was partially offset by decreases in approved return on common equity, the completion of the Stall Unit construction project in June 2010 and the discontinuance of AFUDC in Arkansas related to Turk Plant construction.
|
| · | Interest Expense increased $12 million primarily due to increased long-term debt outstanding.
|
| · | Income Tax Expense increased $26 million primarily due to an increase in pretax book income and other book/tax differences accounted for on a flow-through basis.
|
FINANCIAL CONDITION
LIQUIDITY
SWEPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity. SWEPCo relies upon ready access to capital markets, cash flows from operations and access to the Utility Money Pool to fund current operations and capital expenditures. See the “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 230 for additional discussion of liquidity.
Credit Ratings
In June 2010, Fitch downgraded SWEPCo's senior unsecured rating to BBB. Further downgrades in SWEPCo's ratings by one of the rating agencies could increase SWEPCo's borrowing costs and affect SWEPCo's ability to finance construction costs.
CASH FLOW
Cash flows for the nine months ended September 30, 2010 and 2009 were as follows:
| | 2010 | | | 2009 | |
| | (in thousands) | |
Cash and Cash Equivalents at Beginning of Period | | $ | 1,661 | | | $ | 1,910 | |
Net Cash Flows from Operating Activities | | | 168,196 | | | | 335,922 | |
Net Cash Flows Used for Investing Activities | | | (449,053 | ) | | | (472,183 | ) |
Net Cash Flows from Financing Activities | | | 281,078 | | | | 136,440 | |
Net Increase in Cash and Cash Equivalents | | | 221 | | | | 179 | |
Cash and Cash Equivalents at End of Period | | $ | 1,882 | | | $ | 2,089 | |
Operating Activities
Net Cash Flows from Operating Activities were $168 million in 2010. SWEPCo produced Net Income of $139 million during the period and had a noncash item of $95 million for Depreciation and Amortization, partially offset by $37 million for Allowance for Equity Funds Used During Construction. SWEPCo contributed $27 million to the qualified pension trust. 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 $49 million inflow from Accrued Taxes, Net was the result of an increase in accruals related to federa l and property taxes. The $36 million outflow from Accounts Payable was primarily due to decreases related to customer accounts factored, net and purchased power payable. The $28 million inflow from Fuel, Materials and Supplies was primarily due to decreased coal and lignite inventories. The $24 million outflow from Accounts Receivable, Net was primarily due to increased affiliated receivables.
Net Cash Flows from Operating Activities were $336 million in 2009. SWEPCo produced Net Income of $107 million during the period and had a noncash item of $109 million for Depreciation and Amortization, partially offset by $32 million in Allowance for Equity Funds Used During Construction and $21 million 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 $81 million inflow from Accounts Receivable, Net was primarily due to the receipt of payment for SIA from the AEP East companies. The $53 million outflow from Other Current Liabilities was due to a decrease in check clearing, a refund to wholesale customers for the SIA and payments of employee-related expenses. The $50 million inflow from Accrued Taxes, Net was the result of an increase in accruals related to federal and property taxes. The $25 million inflow from Accounts Payable was primarily due to increases in accruals related to tax payments, partially offset by a decrease in customer accounts factored, net. The $20 million outflow from Accrued Interest was primarily due to timing between accruals and payments for Senior Unsecured Notes. The $62 million inflow from Fuel Over/Under-Recovery, Net was the result of a surcharge to customers in Texas for under-recovered fuel and a decrease in fuel costs.
Investing Activities
Net Cash Flows Used for Investing Activities during 2010 and 2009 were $449 million and $472 million, respectively. Construction Expenditures of $288 million and $470 million in 2010 and 2009, respectively, were primarily related to new generation projects at the Turk Plant and Stall Unit. SWEPCo’s net increase in loans to the Utility Money Pool during 2010 and 2009 were $162 million and $107 million, respectively. Proceeds from Sales of Assets in 2009 primarily included $104 million related to the sale of a portion of Turk Plant to joint owners.
Financing Activities
Net Cash Flows from Financing Activities were $281 million during 2010 related to a $350 million issuance of Senior Unsecured Notes and a $54 million issuance of Pollution Control Bonds. These increases were partially offset by a $54 million retirement of Pollution Control Bonds and a $50 million retirement of Notes Payable – Affiliated.
Net Cash Flows from Financing Activities were $136 million during 2009. SWEPCo received a capital contribution from Parent of $143 million and $12 million from proceeds on sale leaseback of a utility property.
Long-term debt issuances and retirements during the first nine months of 2010 were:
Issuances | | | | | | | | |
| | | Principal | | Interest | | Due |
| Type of Debt | | Amount | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| Senior Unsecured Notes | | $ | 350,000 | | 6.20 | | 2040 |
| Pollution Control Bonds | | | 53,500 | | 3.25 | | 2015 |
Retirements | | | | | | | |
| | | Principal | | Interest | | Due |
| Type of Debt | | Amount Paid | | Rate | | Date |
| | | (in thousands) | | (%) | | |
| Notes Payable – Affiliated | | $ | 50,000 | | 4.45 | | 2010 |
| Pollution Control Bonds | | | 53,500 | | Variable | | 2019 |
SUMMARY OBLIGATION INFORMATION
A summary of contractual obligations is included in the 2009 Annual Report and has not changed significantly from year-end other than debt issuances and retirements discussed in “Cash Flow” above.MANAGEMENT’S DISCUSSION AND ANALYSIS
EXECUTIVE OVERVIEW
REGULATORY ACTIVITY
Texas Regulatory Activity
In April 2010, a settlement agreement was approved by the PUCT to increase SWEPCo’s base rates by approximately $15 million annually, effective May 2010, including a return on equity of 10.33%. In addition, the settlement agreement will decrease annual depreciation expense by $17 million and allows SWEPCo a $10 million one-year surcharge rider to recover additional vegetation management costs that SWEPCo must spend within two years. See “2009 Texas Base Rate Filing” section of Note 3.
Turk Plant
SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in-servicein service in 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility. The Turk PlantSWEPCo’s share of construction costs is currently estimated to cost $1.7 billion, excluding AFUDC, plus an additional $132 million for transmission, excluding AFUDC. SWEPCo’s share is currently estimated to costbe $1.3 billion, excluding AFUDC, plus an additional $132$125 million for transmission, excluding AFUDC. NoticesThe APSC, LPSC and PUCT approved SWEPCo’s original application to build the Turk Plant. In June 2010, the APSC issued an order which reversed and set aside the previously granted Certificate of appealEnvironmental Compatibility and Public Need. Various proceedings are outstandingpending that challenge the Turk Plant’s construction and its approved wetlands and air permits. In 2010, the motions for preliminary injunction were partially granted. According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Circuit CourtTurk Plant must immediately stop. Mitigation measures required by the permit are authorized and may be completed. The preliminary injunction affects portions of Hempstead County, Arkansasthe water intake and portions of two transmission lines. A hearing on SWEPCo’s appeal was held in March 2011. Management is unable to predict the Federal Courttiming of Appeals. Matters are also outstanding at the Texas Courtoutcome related to this proceeding.
Management expects that SWEPCo will ultimately be able to complete construction of Appeals, the APSCTurk Plant and related transmission facilities and place those facilities in service. However, if SWEPCo is unable to complete the LPSC.Turk Plant construction, including the related transmission facilities, and place the Turk Plant in service or if SWEPCo cannot recover all of its investment in and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition. See “Turk Plant” ; section of Note 3.2.
LITIGATION AND ENVIRONMENTAL ISSUESLitigation and Environmental Issues
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 resolution will be or the timing and amount of any loss, fine or penalty may be. Management assesses the probability of loss for each contingency and accrues a liability for cases which have a probable likelihood of loss if the loss 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 20092010 Annual Report. Also, see Note 32 – Rate Matters and Note 43 – Commitments, Guarantees and Contingencies within the Condensed Notes to Condens edCondensed Financial Statements beginning on page 161.143. Adverse results in these proceedings have the potential to materially affect net income, financial condition and cash flows.
See the “Executive Overview” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” section beginning on page 230201 for additional discussion of relevant factors.
RESULTS OF OPERATIONS | | | | | |
| | | | | | | |
KWH Sales/Degree Days | | | | | |
| | | | | | |
Summary of KWH Energy Sales |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in millions of KWH) |
Retail: | | | | | |
| Residential | | 1,604 | | | 1,599 |
| Commercial | | 1,366 | | | 1,314 |
| Industrial | | 1,252 | | | 1,146 |
| Miscellaneous | | 20 | | | 19 |
Total Retail | | 4,242 | | | 4,078 |
| | | | | |
Wholesale | | 1,877 | | | 1,813 |
| | | | | |
Total KWHs | | 6,119 | | | 5,891 |
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.
Summary of Heating and Cooling Degree Days |
|
| | Three Months Ended March 31, |
| 2011 | | 2010 |
| | (in degree days) |
| | | | | | |
Actual - Heating (a) | | 849 | | | 1,038 |
Normal - Heating (b) | | 745 | | | 738 |
| | | | | | |
Actual - Cooling (c) | | 51 | | | 5 |
Normal - Cooling (b) | | 31 | | | 31 |
| | | | | | |
(a) | 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) | Western Region cooling degree days are calculated on a 65 degree temperature base. |
First Quarter of 2011 Compared to First Quarter of 2010 |
| | | |
Reconciliation of First Quarter of 2010 to First Quarter of 2011 | |
Net Income | |
(in millions) | |
| | | |
First Quarter of 2010 | | $ | 31 | |
| | | | |
Changes in Gross Margin: | | | | |
Retail Margins (a) | | | 22 | |
Off-system Sales | | | (1 | ) |
Transmission Revenues | | | (2 | ) |
Other Revenues | | | 1 | |
Total Change in Gross Margin | | | 20 | |
| | | | |
Total Expenses and Other: | | | | |
Other Operation and Maintenance | | | (8 | ) |
Taxes Other Than Income Taxes | | | (1 | ) |
Other Income | | | (5 | ) |
Interest Expense | | | (4 | ) |
Total Expenses and Other | | | (18 | ) |
| | | | |
Income Tax Expense | | | (3 | ) |
| | | | |
First Quarter of 2011 | | $ | 30 | |
| | | | | | | | |
(a) | Includes firm wholesale sales to municipals and cooperatives. |
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 $22 million primarily due to: |
| · | A $13 million increase primarily due to rate increases, including revenue increases from base rates in Texas and rate riders in Arkansas. |
| · | An $8 million increase in retail sales primarily due to increases in residential and commercial customers and usage in the industrial class. |
· | Transmission Revenues decreased $2 million due to lower rates in the SPP region. |
Total Expenses and Other and Income Tax Expense changed between years as follows:
· | Other Operation and Maintenance expenses increased $8 million primarily due to an increase in distribution maintenance resulting from increased storm-related and overhead line maintenance expenses. |
· | Other Income decreased $5 million primarily due to a decrease in the equity component of AFUDC as a result of the completed construction of the Stall Unit in June 2010. |
· | Interest Expense increased $4 million primarily due to increased long-term debt outstanding. |
· | Income Tax Expense increased $3 million primarily due to an increase in pretax book income and other book/tax differences which are accounted for on a flow-through basis. |
FINANCIAL CONDITION
LIQUIDITY
SWEPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity. SWEPCo has $41 million of Pollution Control Bonds that will mature in the third quarter of 2011. SWEPCo relies upon ready access to capital markets, 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 beginning on page 201 for additional discussion of liquidity.
Credit Ratings
SWEPCo’s ultimate access to capital markets may depend on its credit ratings. In addition, a credit rating downgrade of SWEPCo by one of the rating agencies could increase SWEPCo’s borrowing costs. Failure to maintain investment grade ratings may constrain SWEPCo’s ability to participate in the Utility Money Pool or the amount of SWEPCo’s receivables securitized by AEP Credit. Counterparty concerns about SWEPCo’s credit quality could subject SWEPCo to additional collateral demands under adequate assurance clauses under derivative and non-derivative energy contracts.
CASH FLOW
Cash flows for the three months ended March 31, 2011 and 2010 were as follows:
| | 2011 | | | 2010 | |
| | (in thousands) | |
Cash and Cash Equivalents at Beginning of Period | | $ | 1,514 | | | $ | 1,661 | |
Net Cash Flows from (Used for) Operating Activities | | | 52,108 | | | | (21,572 | ) |
Net Cash Flows Used for Investing Activities | | | (39,011 | ) | | | (277,945 | ) |
Net Cash Flows from (Used for) Financing Activities | | | (10,537 | ) | | | 299,536 | |
Net Increase in Cash and Cash Equivalents | | | 2,560 | | | | 19 | |
Cash and Cash Equivalents at End of Period | | $ | 4,074 | | | $ | 1,680 | |
Operating Activities
Net Cash Flows from Operating Activities were $52 million in 2011. SWEPCo produced Net Income of $30 million during the period and had noncash items of $33 million for Depreciation and Amortization and $15 million for Deferred Income Taxes, partially offset by a $31 million increase in the deferral of Property Taxes and $11 million in Allowance for Equity Funds Used During Construction. 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 $30 million inflow from Accrued Taxes, Net was the result of an increase in property tax accruals. The $22 million outflow from Accrued Interest was primarily due to the timing of interest payments on long-term debt in relation to the accruals. The $11 million outflow from Accounts Payable was primarily due to a payment on a third party fuel transportation contract.
Net Cash Flows Used for Operating Activities were $22 million in 2010. SWEPCo produced Net Income of $31 million during the period and had a noncash expense item of $33 million for Depreciation and Amortization, partially offset by a $29 million increase in the deferral of Property Taxes and $16 million in Allowance for Equity Funds Used During Construction. 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 $46 million outflow from Accounts Payable was primarily due to timing differences for payments of items accrued at December 31, 2009. The $39 million inflow from Accrued Taxes, Net was the result of an increase in property tax accruals. The $17 million inflow from Fuel, Materials and Supplies was primarily due to a reduction in coal inventory and a decrease in the average cost of coal per ton. The $16 million outflow from Accrued Interest was primarily due to the timing of interest payments on long-term debt in relation to the accruals.
Investing Activities
Net Cash Flows Used for Investing Activities during 2011 and 2010 were $39 million and $278 million, respectively. Construction Expenditures of $114 million and $89 million in 2011 and 2010, respectively, were primarily related to generation projects at the Turk Plant and Stall Unit. The Stall Unit was placed in service in the second quarter of 2010. During 2011, SWEPCo decreased loans to the Utility Money Pool by $77 million. During 2010, SWEPCo increased loans to the Utility Money Pool by $187 million.
Financing Activities
Net Cash Flows Used for Financing Activities were $11 million during 2011. SWEPCo had a $6 million net decrease in revolving credit facility balances.
Net Cash Flows from Financing Activities were $300 million during 2010. SWEPCo issued $350 million of Senior Unsecured Notes and $54 million of Pollution Control Bonds. These increases were partially offset by a $54 million retirement of Pollution Control Bonds and a $50 million retirement of Notes Payable – Affiliated.
CONTRACTUAL OBLIGATION INFORMATION
A summary of contractual obligations is included in the 2010 Annual Report and has not changed significantly from year-end.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
See the “Critical Accounting Policies and Estimates” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 20092010 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets and pension and other postretirement benefits.
See the “New Accounting“Accounting Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230201 for a discussion of the adoption and impact of new accounting pronouncements.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK MANAGEMENT ACTIVITIES
See “Quantitative And Qualitative Disclosures About Risk Management Activities”Market Risk” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 230201 for a discussion of risk management activities.market risk.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | | SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | |
CONDENSED CONSOLIDATED STATEMENTS OF INCOME | CONDENSED CONSOLIDATED STATEMENTS OF INCOME | | CONDENSED CONSOLIDATED STATEMENTS OF INCOME | |
For the Three and Nine Months Ended September 30, 2010 and 2009 | | |
For the Three Months Ended March 31, 2011 and 2010 | | For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | (in thousands) | | (in thousands) | |
(Unaudited) | (Unaudited) | | (Unaudited) | |
| | |
| | Three Months Ended | | | Nine Months Ended | | | | | | | |
| | 2010 | | | 2009 | | | 2010 | | | 2009 | | | 2011 | | | 2010 | |
REVENUES | | | | | | | | | | | | | | | | | | |
Electric Generation, Transmission and Distribution | | $ | 459,013 | | | $ | 392,616 | | | $ | 1,139,748 | | | $ | 1,021,991 | | | $ | 347,067 | | | $ | 333,078 | |
Sales to AEP Affiliates | | | 21,356 | | | | 9,420 | | | | 43,920 | | | | 23,470 | | | | 15,579 | | | | 9,333 | |
Lignite Revenues – Nonaffiliated | | | - | | | | 12,334 | | | | - | | | | 30,572 | | |
Other Revenues | | | 613 | | | | 604 | | | | 1,585 | | | | 1,525 | | | | 309 | | | | 393 | |
TOTAL REVENUES | | | 480,982 | | | | 414,974 | | | | 1,185,253 | | | | 1,077,558 | | | | 362,955 | | | | 342,804 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
EXPENSES | | | | | | | | | | | | | | | | | | | | | | | | |
Fuel and Other Consumables Used for Electric Generation | | | 194,340 | | | | 161,879 | | | | 452,279 | | | | 405,329 | | | | 134,012 | | | | 122,888 | |
Purchased Electricity for Resale | | | 29,794 | | | | 30,413 | | | | 94,521 | | | | 85,149 | | | | 38,589 | | | | 41,886 | |
Purchased Electricity from AEP Affiliates | | | 4,191 | | | | 6,865 | | | | 18,154 | | | | 30,395 | | | | 2,111 | | | | 9,752 | |
Other Operation | | | 52,839 | | | | 64,686 | | | | 193,357 | | | | 178,456 | | | | 54,068 | | | | 58,253 | |
Maintenance | | | 23,979 | | | | 17,267 | | | | 69,531 | | | | 67,283 | | | | 29,391 | | | | 17,419 | |
Depreciation and Amortization | | | 31,828 | | | | 36,714 | | | | 94,939 | | | | 109,065 | | | | 33,290 | | | | 33,243 | |
Taxes Other Than Income Taxes | | | 15,583 | | | | 14,127 | | | | 47,058 | | | | 44,995 | | | | 16,966 | | | | 15,895 | |
TOTAL EXPENSES | | | 352,554 | | | | 331,951 | | | | 969,839 | | | | 920,672 | | | | 308,427 | | | | 299,336 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 128,428 | | | | 83,023 | | | | 215,414 | | | | 156,886 | | | | 54,528 | | | | 43,468 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | | | | |
Interest Income | | | 186 | | | | 388 | | | | 434 | | | | 1,205 | | |
Allowance for Equity Funds Used During Construction | | | 8,651 | | | | 12,932 | | | | 36,630 | | | | 31,706 | | |
Other Income | | | | 10,540 | | | | 15,596 | |
Interest Expense | | | (23,459 | ) | | | (16,605 | ) | | | (63,478 | ) | | | (51,894 | ) | | | (22,425 | ) | | | (18,544 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAX EXPENSE AND | | | | | | | | | | | | | | | | | |
EQUITY EARNINGS | | | 113,806 | | | | 79,738 | | | | 189,000 | | | | 137,903 | | |
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS | | | | 42,643 | | | | 40,520 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Income Tax Expense | | | 32,870 | | | | 14,680 | | | | 51,733 | | | | 25,367 | | | | 13,396 | | | | 10,156 | |
Equity Earnings of Unconsolidated Subsidiaries | | | 749 | | | | - | | | | 2,206 | | | | - | | |
| | | | | | | | | | | | | | | | | |
INCOME BEFORE EXTRAORDINARY LOSS | | | 81,685 | | | | 65,058 | | | | 139,473 | | | | 112,536 | | |
| | | | | | | | | | | | | | | | | |
EXTRAORDINARY LOSS, NET OF TAX | | | - | | | | - | | | | - | | | | (5,325 | ) | |
Equity Earnings of Unconsolidated Subsidiary | | | | 580 | | | | 719 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
NET INCOME | | | 81,685 | | | | 65,058 | | | | 139,473 | | | | 107,211 | | | | 29,827 | | | | 31,083 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Less: Net Income Attributable to Noncontrolling Interest | | | 774 | | | | 1,022 | | | | 3,198 | | | | 2,971 | | | | 1,082 | | | | 1,151 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
NET INCOME ATTRIBUTABLE TO SWEPCo | | | | | | | | | | | | | | | | | |
SHAREHOLDERS | | | 80,911 | | | | 64,036 | | | | 136,275 | | | | 104,240 | | |
NET INCOME ATTRIBUTABLE TO SWEPCo SHAREHOLDERS | | | | 28,745 | | | | 29,932 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Less: Preferred Stock Dividend Requirements | | | 58 | | | | 58 | | | | 172 | | | | 172 | | | | 57 | | | | 57 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON | | | | | | | | | | | | | | | | | |
SHAREHOLDER | | $ | 80,853 | | | $ | 63,978 | | | $ | 136,103 | | | $ | 104,068 | | |
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER | | | $ | 28,688 | | | $ | 29,875 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
The common stock of SWEPCo is wholly-owned by AEP. | | | | | | | | | | | | | | | | | The common stock of SWEPCo is wholly-owned by AEP. | |
| | | | | | | | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | | See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN | EQUITY AND COMPREHENSIVE INCOME (LOSS) | For the Nine Months Ended September 30, 2010 and 2009 | |
For the Three Months Ended March 31, 2011 and 2010 | | For the Three Months Ended March 31, 2011 and 2010 |
(in thousands) | (Unaudited) | | | | | SWEPCo Common Shareholder | | | | | | | SWEPCo Common Shareholder | | | | |
| | | | | | | | | | | Accumulated | | | | | | | | | | | | | | | Accumulated | | | | |
| | | | | | | | | | | | Other | | | | | | | | | | | | | | | | Other | | | | |
| | | Common | | Paid-in | | Retained | | Comprehensive | | Noncontrolling | | | | | Common | | Paid-in | | Retained | | Comprehensive | | Noncontrolling | | |
| | | Stock | | Capital | | Earnings | | Income (Loss) | | Interest | | Total | | | Stock | | Capital | | Earnings | | Income (Loss) | | Interest | | Total |
| | | | | | | | | | | | | | | | | |
TOTAL EQUITY – DECEMBER 31, 2008 | | $ | 135,660 | | $ | 530,003 | | $ | 615,110 | | $ | (32,120) | | $ | 276 | | $ | 1,248,929 | |
| | | | | | | | | | | | | |
Capital Contribution from Parent | | | | 142,500 | | | | | | | | 142,500 | |
Common Stock Dividends – Nonaffiliated | | | | | | | | | | (2,886) | | (2,886) | |
Preferred Stock Dividends | | | | | | (172) | | | | | | (172) | |
Other Changes in Equity | | | | 2,476 | | (2,476) | | | | | | | - | |
SUBTOTAL – EQUITY | | | | | | | | | | | | | 1,388,371 | |
| | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | |
| | Cash Flow Hedges, Net of Tax of $421 | | | | | | | | 782 | | | | 782 | |
| | Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | |
| | Costs, Net of Tax of $8,919 | | | | | | | | 16,563 | | | | 16,563 | |
NET INCOME | | | | | | 104,240 | | | | 2,971 | | | 107,211 | |
TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | 124,556 | |
| | | | | | | | | | | | | |
TOTAL EQUITY – SEPTEMBER 30, 2009 | | $ | 135,660 | | $ | 674,979 | | $ | 716,702 | | $ | (14,775) | | $ | 361 | | $ | 1,512,927 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
TOTAL EQUITY – DECEMBER 31, 2009 | TOTAL EQUITY – DECEMBER 31, 2009 | | $ | 135,660 | | $ | 674,979 | | $ | 726,478 | | $ | (12,991) | | $ | 31 | | $ | 1,524,157 | TOTAL EQUITY – DECEMBER 31, 2009 | | $ | 135,660 | | $ | 674,979 | | $ | 726,478 | | $ | (12,991) | | $ | 31 | | $ | 1,524,157 |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Common Stock Dividends – Nonaffiliated | Common Stock Dividends – Nonaffiliated | | | | | | | | | | (2,966) | | (2,966) | Common Stock Dividends – Nonaffiliated | | | | | | | | | | (809) | | (809) |
Preferred Stock Dividends | Preferred Stock Dividends | | | | | | (172) | | | | | | | (172) | Preferred Stock Dividends | | | | | | (57) | | | | | | | (57) |
SUBTOTAL – EQUITY | SUBTOTAL – EQUITY | | | | | | | | | | | | | 1,521,019 | SUBTOTAL – EQUITY | | | | | | | | | | | | | 1,523,291 |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | COMPREHENSIVE INCOME | | | | | | | | | | | | | COMPREHENSIVE INCOME | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | |
| | Cash Flow Hedges, Net of Tax of $248 | | | | | | | | 461 | | | | 461 | | Cash Flow Hedges, Net of Tax of $42 | | | | | | | | 88 | | | | 88 |
| | Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | Amortization of Pension and OPEB Deferred Costs, | | | | | | | | | | | | |
| | Costs, Net of Tax of $379 | | | | | | | | 703 | | | | 703 | | Net of Tax of $127 | | | | | | | | 235 | | | | 235 |
NET INCOME | NET INCOME | | | | | | 136,275 | | | | 3,198 | | | 139,473 | NET INCOME | | | | | | 29,932 | | | | 1,151 | | | 31,083 |
TOTAL COMPREHENSIVE INCOME | TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | 140,637 | TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | 31,406 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
TOTAL EQUITY – SEPTEMBER 30, 2010 | | $ | 135,660 | | $ | 674,979 | | $ | 862,581 | | $ | (11,827) | | $ | 263 | | $ | 1,661,656 | |
TOTAL EQUITY – MARCH 31, 2010 | | TOTAL EQUITY – MARCH 31, 2010 | | $ | 135,660 | | $ | 674,979 | | $ | 756,353 | | $ | (12,668) | | $ | 373 | | $ | 1,554,697 |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | |
TOTAL EQUITY – DECEMBER 31, 2010 | | TOTAL EQUITY – DECEMBER 31, 2010 | | $ | 135,660 | | $ | 674,979 | | $ | 868,840 | | $ | (12,491) | | $ | 361 | | $ | 1,667,349 |
| | | | | | | | | | | | | | |
Common Stock Dividends – Nonaffiliated | | Common Stock Dividends – Nonaffiliated | | | | | | | | | | (1,077) | | (1,077) |
Preferred Stock Dividends | | Preferred Stock Dividends | | | | | | (57) | | | | | | | (57) |
SUBTOTAL – EQUITY | | SUBTOTAL – EQUITY | | | | | | | | | | | | | 1,666,215 |
| | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | COMPREHENSIVE INCOME | | | | | | | | | | | | |
Other Comprehensive Income, Net of Taxes: | | Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | |
| | | Cash Flow Hedges, Net of Tax of $202 | | | | | | | | 376 | | | | 376 |
| | | Amortization of Pension and OPEB Deferred Costs, | | | | | | | | | | | | |
| | | Net of Tax of $69 | | | | | | | | 128 | | | | 128 |
NET INCOME | | NET INCOME | | | | | | 28,745 | | | | 1,082 | | | 29,827 |
TOTAL COMPREHENSIVE INCOME | | TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | 30,331 |
| | | | | | | | | | | | | | | |
TOTAL EQUITY – MARCH 31, 2011 | | TOTAL EQUITY – MARCH 31, 2011 | | $ | 135,660 | | $ | 674,979 | | $ | 897,528 | | $ | (11,987) | | $ | 366 | | $ | 1,696,546 |
| | | | | | | | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | | See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
ASSETS | |
September 30, 2010 and December 31, 2009 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2010 | | | 2009 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 1,882 | | | $ | 1,661 | |
Advances to Affiliates | | | 213,689 | | | | 34,883 | |
Accounts Receivable: | | | | | | | | |
Customers | | | 23,833 | | | | 46,657 | |
Affiliated Companies | | | 42,393 | | | | 19,542 | |
Miscellaneous | | | 23,753 | | | | 9,952 | |
Allowance for Uncollectible Accounts | | | (454 | ) | | | (64 | ) |
Total Accounts Receivable | | | 89,525 | | | | 76,087 | |
Fuel | | | | | | | | |
(September 30, 2010 amount includes $31,649 related to Sabine) | | | 86,154 | | | | 121,453 | |
Materials and Supplies | | | 48,770 | | | | 54,484 | |
Risk Management Assets | | | 2,017 | | | | 3,049 | |
Deferred Income Tax Benefits | | | 14,470 | | | | 13,820 | |
Accrued Tax Benefits | | | 2,859 | | | | 16,164 | |
Regulatory Asset for Under-Recovered Fuel Costs | | | 7,622 | | | | 1,639 | |
Prepayments and Other Current Assets | | | 20,388 | | | | 20,503 | |
TOTAL CURRENT ASSETS | | | 487,376 | | | | 343,743 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Production | | | 2,267,397 | | | | 1,837,318 | |
Transmission | | | 906,837 | | | | 870,069 | |
Distribution | | | 1,476,596 | | | | 1,447,559 | |
Other Property, Plant and Equipment | | | | | | | | |
(September 30, 2010 amount includes $224,987 related to Sabine) | | | 640,697 | | | | 733,310 | |
Construction Work in Progress | | | 1,003,889 | | | | 1,176,639 | |
Total Property, Plant and Equipment | | | 6,295,416 | | | | 6,064,895 | |
Accumulated Depreciation and Amortization | | | | | | | | |
(September 30, 2010 amount includes $89,703 related to Sabine) | | | 2,080,258 | | | | 2,086,333 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 4,215,158 | | | | 3,978,562 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 295,590 | | | | 268,165 | |
Long-term Risk Management Assets | | | 419 | | | | 84 | |
Deferred Charges and Other Noncurrent Assets | | | 80,591 | | | | 49,479 | |
TOTAL OTHER NONCURRENT ASSETS | | | 376,600 | | | | 317,728 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 5,079,134 | | | $ | 4,640,033 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | |
| | | | | | | | |
| | | | | | |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
LIABILITIES AND EQUITY | |
September 30, 2010 and December 31, 2009 | |
(Unaudited) | |
| |
| | 2010 | | | 2009 | |
| | (in thousands) | |
CURRENT LIABILITIES | | | | | | |
Accounts Payable: | | | | | | |
General | | $ | 168,300 | | | $ | 160,870 | |
Affiliated Companies | | | 45,767 | | | | 59,818 | |
Short-term Debt – Nonaffiliated | | | 3,170 | | | | 6,890 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 41,135 | | | | 4,406 | |
Long-term Debt Due Within One Year – Affiliated | | | - | | | | 50,000 | |
Risk Management Liabilities | | | 523 | | | | 844 | |
Customer Deposits | | | 43,467 | | | | 41,269 | |
Accrued Taxes | | | 58,319 | | | | 24,720 | |
Accrued Interest | | | 18,088 | | | | 33,179 | |
Obligations Under Capital Leases | | | 12,679 | | | | 14,617 | |
Regulatory Liability for Over-Recovered Fuel Costs | | | 5,377 | | | | 13,762 | |
Provision for SIA Refund | | | 20,766 | | | | 19,307 | |
Other Current Liabilities | | | 45,115 | | | | 71,781 | |
TOTAL CURRENT LIABILITIES | | | 462,706 | | | | 501,463 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 1,728,322 | | | | 1,419,747 | |
Long-term Risk Management Liabilities | | | 272 | | | | 221 | |
Deferred Income Taxes | | | 514,576 | | | | 485,936 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 385,825 | | | | 333,935 | |
Asset Retirement Obligations | | | 49,720 | | | | 60,562 | |
Employee Benefits and Pension Obligations | | | 98,684 | | | | 125,956 | |
Obligations Under Capital Leases | | | 114,017 | | | | 134,044 | |
Deferred Credits and Other Noncurrent Liabilities | | | 58,659 | | | | 49,315 | |
TOTAL NONCURRENT LIABILITIES | | | 2,950,075 | | | | 2,609,716 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 3,412,781 | | | | 3,111,179 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 4,697 | | | | 4,697 | |
| | | | | | | | |
Rate Matters (Note 3) | | | | | | | | |
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 | | | 674,979 | | | | 674,979 | |
Retained Earnings | | | 862,581 | | | | 726,478 | |
Accumulated Other Comprehensive Income (Loss) | | | (11,827 | ) | | | (12,991 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | | 1,661,393 | | | | 1,524,126 | |
| | | | | | | | |
Noncontrolling Interest | | | 263 | | | | 31 | |
| | | | | | | | |
TOTAL EQUITY | | | 1,661,656 | | | | 1,524,157 | |
| | | | | | | | |
TOTAL LIABILITIES AND EQUITY | | $ | 5,079,134 | | | $ | 4,640,033 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |
For the Nine Months Ended September 30, 2010 and 2009 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2010 | | | 2009 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 139,473 | | | $ | 107,211 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 94,939 | | | | 109,065 | |
Deferred Income Taxes | | | 1,227 | | | | (20,571 | ) |
Extraordinary Loss, Net of Tax | | | - | | | | 5,325 | |
Allowance for Equity Funds Used During Construction | | | (36,630 | ) | | | (31,706 | ) |
Mark-to-Market of Risk Management Contracts | | | 230 | | | | 510 | |
Pension Contributions to Qualified Plan Trust | | | (26,684 | ) | | | - | |
Fuel Over/Under-Recovery, Net | | | (14,371 | ) | | | 61,880 | |
Change in Other Noncurrent Assets | | | (16,101 | ) | | | 13,498 | |
Change in Other Noncurrent Liabilities | | | 41,231 | | | | 4,539 | |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | (23,562 | ) | | | 81,322 | |
Fuel, Materials and Supplies | | | 27,811 | | | | 4,396 | |
Accounts Payable | | | (35,890 | ) | | | 24,584 | |
Accrued Taxes, Net | | | 49,249 | | | | 50,027 | |
Accrued Interest | | | (15,085 | ) | | | (19,816 | ) |
Other Current Assets | | | (1,864 | ) | | | (1,017 | ) |
Other Current Liabilities | | | (15,777 | ) | | | (53,325 | ) |
Net Cash Flows from Operating Activities | | | 168,196 | | | | 335,922 | |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (288,043 | ) | | | (470,379 | ) |
Change in Advances to Affiliates, Net | | | (161,873 | ) | | | (106,662 | ) |
Proceeds from Sales of Assets | | | 1,337 | | | | 105,500 | |
Other Investing Activities | | | (474 | ) | | | (642 | ) |
Net Cash Flows Used for Investing Activities | | | (449,053 | ) | | | (472,183 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Capital Contribution from Parent | | | - | | | | 142,500 | |
Issuance of Long-term Debt – Nonaffiliated | | | 399,394 | | | | - | |
Borrowings from Revolving Credit Facilities | | | 74,449 | | | | 90,478 | |
Change in Advances from Affiliates, Net | | | - | | | | (2,526 | ) |
Retirement of Long-term Debt – Nonaffiliated | | | (53,500 | ) | | | (3,304 | ) |
Retirement of Long-term Debt – Affiliated | | | (50,000 | ) | | | - | |
Repayments to Revolving Credit Facilities | | | (78,170 | ) | | | (92,377 | ) |
Proceeds from Sale/Leaseback | | | - | | | | 12,222 | |
Principal Payments for Capital Lease Obligations | | | (8,873 | ) | | | (7,853 | ) |
Dividends Paid on Common Stock – Nonaffiliated | | | (2,966 | ) | | | (2,971 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (172 | ) | | | (172 | ) |
Other Financing Activities | | | 916 | | | | 443 | |
Net Cash Flows from Financing Activities | | | 281,078 | | | | 136,440 | |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 221 | | | | 179 | |
Cash and Cash Equivalents at Beginning of Period | | | 1,661 | | | | 1,910 | |
Cash and Cash Equivalents at End of Period | | $ | 1,882 | | | $ | 2,089 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 72,270 | | | $ | 82,033 | |
Net Cash Paid (Received) for Income Taxes | | | 25,575 | | | | (6,196 | ) |
Noncash Acquisitions Under Capital Leases | | | 653 | | | | 26,175 | |
Construction Expenditures Included in Accounts Payable at September 30, | | | 101,017 | | | | 60,219 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 161. | |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
ASSETS | |
March 31, 2011 and December 31, 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
CURRENT ASSETS | | | | | | |
Cash and Cash Equivalents | | $ | 4,074 | | | $ | 1,514 | |
Advances to Affiliates | | | 9,367 | | | | 86,222 | |
Accounts Receivable: | | | | | | | | |
Customers | | | 30,005 | | | | 34,434 | |
Affiliated Companies | | | 43,583 | | | | 43,219 | |
Miscellaneous | | | 19,879 | | | | 17,739 | |
Allowance for Uncollectible Accounts | | | (768 | ) | | | (588 | ) |
Total Accounts Receivable | | | 92,699 | | | | 94,804 | |
Fuel | | | | | | | | |
(March 31, 2011 and December 31, 2010 amounts include $29,201 and | | | | | | | | |
$35,055, respectively, related to Sabine) | | | 86,985 | | | | 91,777 | |
Materials and Supplies | | | 50,699 | | | | 50,395 | |
Risk Management Assets | | | 757 | | | | 1,209 | |
Deferred Income Tax Benefits | | | 12,085 | | | | 15,529 | |
Accrued Tax Benefits | | | 33,747 | | | | 37,900 | |
Regulatory Asset for Under-Recovered Fuel Costs | | | 844 | | | | 758 | |
Prepayments and Other Current Assets | | | 24,616 | | | | 24,270 | |
TOTAL CURRENT ASSETS | | | 315,873 | | | | 404,378 | |
| | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
Electric: | | | | | | | | |
Generation | | | 2,299,370 | | | | 2,297,463 | |
Transmission | | | 947,670 | | | | 943,724 | |
Distribution | | | 1,623,579 | | | | 1,611,129 | |
Other Property, Plant and Equipment | | | | | | | | |
(March 31, 2011 and December 31, 2010 amounts include $229,639 and | | | | | | | | |
$224,857, respectively, related to Sabine) | | | 636,470 | | | | 632,158 | |
Construction Work in Progress | | | 1,162,297 | | | | 1,071,603 | |
Total Property, Plant and Equipment | | | 6,669,386 | | | | 6,556,077 | |
Accumulated Depreciation and Amortization | | | | | | | | |
(March 31, 2011 and December 31, 2010 amounts include $95,616 and | | | | | | | | |
$91,840, respectively, related to Sabine) | | | 2,158,412 | | | | 2,130,351 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 4,510,974 | | | | 4,425,726 | |
| | | | | | | | |
OTHER NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 343,306 | | | | 332,698 | |
Long-term Risk Management Assets | | | 641 | | | | 438 | |
Deferred Charges and Other Noncurrent Assets | | | 108,687 | | | | 80,327 | |
TOTAL OTHER NONCURRENT ASSETS | | | 452,634 | | | | 413,463 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 5,279,481 | | | $ | 5,243,567 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
| | | | | | | | |
| | | | | | |
| | | | | | |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | |
CONDENSED CONSOLIDATED BALANCE SHEETS | |
LIABILITIES AND EQUITY | |
March 31, 2011 and December 31, 2010 | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
| | (in thousands) | |
CURRENT LIABILITIES | | | | | | |
Accounts Payable: | | | | | | |
General | | $ | 143,290 | | | $ | 162,271 | |
Affiliated Companies | | | 70,582 | | | | 64,474 | |
Short-term Debt – Nonaffiliated | | | - | | | | 6,217 | |
Long-term Debt Due Within One Year – Nonaffiliated | | | 61,135 | | | | 41,135 | |
Risk Management Liabilities | | | 2,225 | | | | 4,067 | |
Customer Deposits | | | 50,638 | | | | 48,245 | |
Accrued Taxes | | | 62,358 | | | | 30,516 | |
Accrued Interest | | | 17,721 | | | | 39,856 | |
Obligations Under Capital Leases | | | 13,752 | | | | 13,265 | |
Regulatory Liability for Over-Recovered Fuel Costs | | | 9,444 | | | | 16,432 | |
Provision for SIA Refund | | | 4,239 | | | | 7,698 | |
Other Current Liabilities | | | 49,248 | | | | 59,420 | |
TOTAL CURRENT LIABILITIES | | | 484,632 | | | | 493,596 | |
| | | | | | | | |
NONCURRENT LIABILITIES | | | | | | | | |
Long-term Debt – Nonaffiliated | | | 1,708,448 | | | | 1,728,385 | |
Long-term Risk Management Liabilities | | | 355 | | | | 338 | |
Deferred Income Taxes | | | 627,682 | | | | 624,333 | |
Regulatory Liabilities and Deferred Investment Tax Credits | | | 406,342 | | | | 393,673 | |
Asset Retirement Obligations | | | 57,572 | | | | 56,632 | |
Employee Benefits and Pension Obligations | | | 97,347 | | | | 96,314 | |
Obligations Under Capital Leases | | | 116,158 | | | | 115,399 | |
Deferred Credits and Other Noncurrent Liabilities | | | 79,703 | | | | 62,852 | |
TOTAL NONCURRENT LIABILITIES | | | 3,093,607 | | | | 3,077,926 | |
| | | | | | | | |
TOTAL LIABILITIES | | | 3,578,239 | | | | 3,571,522 | |
| | | | | | | | |
Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 4,696 | | | | 4,696 | |
| | | | | | | | |
Rate Matters (Note 2) | | | | | | | | |
Commitments and Contingencies (Note 3) | | | | | | | | |
| | | | | | | | |
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 | | | 674,979 | | | | 674,979 | |
Retained Earnings | | | 897,528 | | | | 868,840 | |
Accumulated Other Comprehensive Income (Loss) | | | (11,987 | ) | | | (12,491 | ) |
TOTAL COMMON SHAREHOLDER’S EQUITY | | | 1,696,180 | | | | 1,666,988 | |
| | | | | | | | |
Noncontrolling Interest | | | 366 | | | | 361 | |
| | | | | | | | |
TOTAL EQUITY | | | 1,696,546 | | | | 1,667,349 | |
| | | | | | | | |
TOTAL LIABILITIES AND EQUITY | | $ | 5,279,481 | | | $ | 5,243,567 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | |
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS | |
For the Three Months Ended March 31, 2011 and 2010 | |
(in thousands) | |
(Unaudited) | |
| |
| | 2011 | | | 2010 | |
OPERATING ACTIVITIES | | | | | | |
Net Income | | $ | 29,827 | | | $ | 31,083 | |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) | | | | | | | | |
Operating Activities: | | | | | | | | |
Depreciation and Amortization | | | 33,290 | | | | 33,243 | |
Deferred Income Taxes | | | 15,440 | | | | 477 | |
Allowance for Equity Funds Used During Construction | | | (10,597 | ) | | | (15,517 | ) |
Mark-to-Market of Risk Management Contracts | | | (1,348 | ) | | | 1,324 | |
Property Taxes | | | (30,534 | ) | | | (28,569 | ) |
Fuel Over/Under-Recovery, Net | | | (7,074 | ) | | | (9,565 | ) |
Change in Other Noncurrent Assets | | | 13,210 | | | | 409 | |
Change in Other Noncurrent Liabilities | | | 20,206 | | | | 3,779 | |
Changes in Certain Components of Working Capital: | | | | | | | | |
Accounts Receivable, Net | | | 2,162 | | | | (5,975 | ) |
Fuel, Materials and Supplies | | | 4,488 | | | | 17,008 | |
Accounts Payable | | | (11,429 | ) | | | (46,408 | ) |
Accrued Taxes, Net | | | 29,884 | | | | 38,552 | |
Accrued Interest | | | (22,192 | ) | | | (15,512 | ) |
Other Current Assets | | | (940 | ) | | | (4,310 | ) |
Other Current Liabilities | | | (12,285 | ) | | | (21,591 | ) |
Net Cash Flows from (Used for) Operating Activities | | | 52,108 | | | | (21,572 | ) |
| | | | | | | | |
INVESTING ACTIVITIES | | | | | | | | |
Construction Expenditures | | | (114,351 | ) | | | (88,731 | ) |
Change in Advances to Affiliates, Net | | | 76,855 | | | | (187,000 | ) |
Other Investing Activities | | | (1,515 | ) | | | (2,214 | ) |
Net Cash Flows Used for Investing Activities | | | (39,011 | ) | | | (277,945 | ) |
| | | | | | | | |
FINANCING ACTIVITIES | | | | | | | | |
Issuance of Long-term Debt – Nonaffiliated | | | - | | | | 399,650 | |
Borrowings from Revolving Credit Facilities | | | 18,478 | | | | 23,743 | |
Retirement of Long-term Debt – Nonaffiliated | | | - | | | | (53,500 | ) |
Retirement of Long-term Debt – Affiliated | | | - | | | | (50,000 | ) |
Repayments to Revolving Credit Facilities | | | (24,695 | ) | | | (17,415 | ) |
Principal Payments for Capital Lease Obligations | | | (3,186 | ) | | | (2,858 | ) |
Dividends Paid on Common Stock – Nonaffiliated | | | (1,077 | ) | | | (809 | ) |
Dividends Paid on Cumulative Preferred Stock | | | (57 | ) | | | (57 | ) |
Other Financing Activities | | | - | | | | 782 | |
Net Cash Flows from (Used for) Financing Activities | | | (10,537 | ) | | | 299,536 | |
| | | | | | | | |
Net Increase in Cash and Cash Equivalents | | | 2,560 | | | | 19 | |
Cash and Cash Equivalents at Beginning of Period | | | 1,514 | | | | 1,661 | |
Cash and Cash Equivalents at End of Period | | $ | 4,074 | | | $ | 1,680 | |
| | | | | | | | |
SUPPLEMENTARY INFORMATION | | | | | | | | |
Cash Paid for Interest, Net of Capitalized Amounts | | $ | 41,646 | | | $ | 31,789 | |
Net Cash Paid (Received) for Income Taxes | | | 698 | | | | (1,062 | ) |
Noncash Acquisitions Under Capital Leases | | | 4,286 | | | | 169 | |
Construction Expenditures Included in Current Liabilities at March 31, | | | 94,536 | | | | 71,395 | |
| | | | | | | | |
See Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries beginning on page 143. | |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
INDEX TOOF 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. The footnotes begin on page 161.143.
| Footnote Reference |
| |
Significant Accounting Matters | Note 1 |
New Accounting Pronouncements and Extraordinary Item | Note 2 |
Rate Matters | Note 32 |
| |
Commitments, Guarantees and Contingencies | Note 43 |
| |
Acquisition | Note 54 |
| |
Benefit Plans | Note 65 |
| |
Business Segments | Note 76 |
| |
Derivatives and Hedging | Note 87 |
| |
Fair Value Measurements | Note 98 |
| |
Income Taxes | Note 109 |
| |
Financing Activities | Note 1110 |
| |
Cost Reduction Initiatives | Note 1211 |
INDEX TOOF 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 |
3.2. | Rate Matters | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
4. | | |
3. | Commitments, Guarantees and Contingencies | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
5. | | |
4. | Acquisition | SWEPCo |
6. | | |
5. | Benefit Plans | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
7. | | |
6. | Business Segments | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
8. | | |
7. | Derivatives and Hedging | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
9. | | |
8. | Fair Value Measurements | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
10. | | |
9. | Income Taxes | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
11. | | |
10. | Financing Activities | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
12.11. | Cost Reduction Initiatives | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
1. SIGNIFICANT ACCOUNTING MATTERS
General
The 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 of the information and footnotes required by GAAP for complete annual financial statements.
In the opinion of management, the unaudited condensed 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. Net income for the three and nine months ended September 30, 2010March 31, 2011 is not necessarily indicative of results that may be expected for the year ending December 31, 2010.2011. The condensed financial statements are unaudited and should be read in conjunction with the audited 20092010 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K for the year ended December 31, 20092010 as filed with the SEC on February 26, 2010.25, 2011.
Variable Interest Entities
The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary 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. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. Also, see the “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.
SWEPCo is the primary beneficiary of Sabine. As of January 1, 2010, SWEPCo is no longer the primary beneficiary of DHLC as defined by new accounting guidance for “Variable Interest Entities.” I&M is the primary beneficiary of DCC Fuel LLC and DCC Fuel II LLC.Fuel. 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. SWEPCo holds a significant variable interest in DHLC.
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 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. In addition, SWEPCo determines how much coal will be mined for each year. Based on these facts, management concluded that SWEPCo is the primary benefic iarybeneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the three months ended September 30,March 31, 2011 and 2010 and 2009 were $30$33 million and $34 million, respectively, and for the nine months ended September 30, 2010 and 2009 were $103 million and $95$43 million, respectively. See the tables below for the classification of Sabine’s assets and liabilities on SWEPCo’s Condensed Consolidated Balance Sheets.
The balances below represent the assets and liabilities of Sabine that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | |
VARIABLE INTEREST ENTITIES | |
March 31, 2011 and December 31, 2010 | |
(in millions) | |
| | Sabine | |
ASSETS | | 2011 | | 2010 | |
Current Assets | | $ | 40 | | $ | 50 | |
Net Property, Plant and Equipment | | | 142 | | | 139 | |
Other Noncurrent Assets | | | 37 | | | 34 | |
Total Assets | | $ | 219 | | $ | 223 | |
| | | | | | | |
LIABILITIES AND EQUITY | | | | | | | |
Current Liabilities | | $ | 44 | | $ | 33 | |
Noncurrent Liabilities | | | 175 | | | 190 | |
Total Liabilities and Equity | | $ | 219 | | $ | 223 | |
I&M has a nuclear fuel lease agreement with DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC (collectively DCC Fuel). DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III LLC are separate legal entities from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on DCC Fuel LLC and DCC Fuel II LLC leases are made semi-annually and began in April 2010 and October 2010, respectively. Payments on the DCC Fuel III LLC lease are made monthly and began in January 2011. Payments on the DCC Fuel III LLC lease for the three months ended March 31, 2011 were $6 million. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the 48, 54 and 54 month lease term, respectively. Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the tables below for the classification of DCC Fuel’s assets and liabilities on I&M’s Condensed Consolidated Balance Sheets.
The balances below represent the assets and liabilities of DCC Fuel that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
VARIABLE INTEREST ENTITIES | |
March 31, 2011 and December 31, 2010 | |
(in millions) | |
| | DCC Fuel | |
ASSETS | | 2011 | | 2010 | |
Current Assets | | $ | 107 | | $ | 92 | |
Net Property, Plant and Equipment | | | 151 | | | 173 | |
Other Noncurrent Assets | | | 93 | | | 112 | |
Total Assets | | $ | 351 | | $ | 377 | |
| | | | | | | |
LIABILITIES AND EQUITY | | | | | | | |
Current Liabilities | | $ | 81 | | $ | 79 | |
Noncurrent Liabilities | | | 270 | | | 298 | |
Total Liabilities and Equity | | $ | 351 | | $ | 377 | |
DHLC is a mining operator who sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and its voting rights equally. Each entity guarantees a 50% share of DHLC’s debt. SWEPCo and CLECO equally approve DHLC’s annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. Based on the shared control of DHLC’s operations, management concluded as of January 1, 2010 that SWEPCo is no longer the primary beneficiary and is no longer required to consolidate DHLC. SWEPCo’s total billings from DHLC for the three months ended September 30,March 31, 2011 and 2010 and 2009 were $14 million
and $12 million, respectively, and for the nine months ended September 30, 2010 and 2009 were $40$13 million and $31$13 million, respectively. SeeSWEPCo is not required to consolidate DHLC as it is not the tables below for the classification of DHLC’s assets and liabilities onprimary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s Condensed Consolidated Balance Sheet at December 31, 2009 as well as SWEPCo’sequity investment and maximum exposure as of September 30, 2010. As of September 30, 2010,in DHLC is reported as an equity investmentincluded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s Condensed Consolidated Balance Sheet. Also, see the “ASU 2009-17 ‘Consolidations’ ” section of Note 2 for a discussion of the impact of new accounting guidance effective January 1, 2010.Sheets.
The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.145
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED |
VARIABLE INTEREST ENTITIES |
September 30, 2010 |
(in millions) |
| | Sabine | |
ASSETS | | | | |
Current Assets | | $ | 42 | |
Net Property, Plant and Equipment | | | 142 | |
Other Noncurrent Assets | | | 35 | |
Total Assets | | $ | 219 | |
| | | | |
LIABILITIES AND EQUITY | | | | |
Current Liabilities | | $ | 26 | |
Noncurrent Liabilities | | | 193 | |
Equity | | | - | |
Total Liabilities and Equity | | $ | 219 | |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | |
VARIABLE INTEREST ENTITIES | |
December 31, 2009 | |
(in millions) | |
| | Sabine | | | DHLC | |
ASSETS | | | | | | |
Current Assets | | $ | 51 | | | $ | 8 | |
Net Property, Plant and Equipment | | | 149 | | | | 44 | |
Other Noncurrent Assets | | | 35 | | | | 11 | |
Total Assets | | $ | 235 | | | $ | 63 | |
| | | | | | | | |
LIABILITIES AND EQUITY | | | | | | | | |
Current Liabilities | | $ | 36 | | | $ | 17 | |
Noncurrent Liabilities | | | 199 | | | | 38 | |
Equity | | | - | | | | 8 | |
Total Liabilities and Equity | | $ | 235 | | | $ | 63 | |
SWEPCo’s investment in DHLC was:
| September 30, 2010 | |
| As Reported on | | | | |
| the Consolidated | | Maximum | |
| Balance Sheet | | Exposure | |
| (in millions) | |
Capital Contribution from SWEPCo | | $ | 7 | | | $ | 7 | |
Retained Earnings | | | 2 | | | | 2 | |
SWEPCo's Guarantee of Debt | | | - | | | | 42 | |
| | | | | | | | |
Total Investment in DHLC | | $ | 9 | | | $ | 51 | |
In September 2009, I&M entered into a nuclear fuel sale and leaseback transaction with DCC Fuel LLC. In April 2010, I&M entered into a nuclear fuel sale and leaseback transaction with DCC Fuel II LLC. DCC Fuel LLC and DCC Fuel II LLC (collectively DCC Fuel) were formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Payments on the leases are made semi-annually and began in April 2010. Payments on the leases for the for the nine months ended September 30, 2010 were $22 million. No payments were made t o DCC Fuel during the third quarter of 2010 and during the year 2009. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the 48 and 54 month lease term, respectively. Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the tables below for the classification of DCC Fuel’s assets and liabilities on I&M’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 are eliminated upon consolidation.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES |
VARIABLE INTEREST ENTITIES |
September 30, 2010 |
(in millions) |
| | DCC Fuel | |
ASSETS | | | | |
Current Assets | | $ | 92 | |
Net Property, Plant and Equipment | | | 118 | |
Other Noncurrent Assets | | | 80 | |
Total Assets | | $ | 290 | |
| | | | |
LIABILITIES AND EQUITY | | | | |
Current Liabilities | | $ | 65 | |
Noncurrent Liabilities | | | 225 | |
Equity | | | - | |
Total Liabilities and Equity | | $ | 290 | |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES |
VARIABLE INTEREST ENTITIES |
December 31, 2009 |
(in millions) |
| | DCC Fuel | |
ASSETS | | | | |
Current Assets | | $ | 47 | |
Net Property, Plant and Equipment | | | 89 | |
Other Noncurrent Assets | | | 57 | |
Total Assets | | $ | 193 | |
| | | | |
LIABILITIES AND EQUITY | | | | |
Current Liabilities | | $ | 39 | |
Noncurrent Liabilities | | | 154 | |
Equity | | | - | |
Total Liabilities and Equity | | $ | 193 | |
| March 31, 2011 | | December 31, 2010 | |
| As Reported on | | | | | As Reported on | | | | |
| the Consolidated | | Maximum | | the Consolidated | | Maximum | |
| Balance Sheet | | Exposure | | Balance Sheet | | Exposure | |
| (in millions) | |
Capital Contribution from SWEPCo | | $ | 8 | | | $ | 8 | | | $ | 6 | | | $ | 6 | |
Retained Earnings | | | 1 | | | | 1 | | | | 2 | | | | 2 | |
SWEPCo's Guarantee of Debt | | | - | | | | 46 | | | | - | | | | 48 | |
| | | | | | | | | | | | | | | | |
Total Investment in DHLC | | $ | 9 | | | $ | 55 | | | $ | 8 | | | $ | 56 | |
AEPSC provides certain managerial and professional services to AEP’s subsidiaries. AEP is the sole equity owner of AEPSC. AEP management controls the activities 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 hassubsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through 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 bil lingsbillings are subject to regulation by the FERC. AEP’sAEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. All Registrant SubsidiariesAEP subsidiaries are considered to have a significant interest in AEPSC due to theirits activity in AEPSC’s cost reimbursement structure. However, no Registrant Subsidiary hasAEP subsidiaries do not have control over AEPSC. 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 September 30, | | | Nine Months Ended September 30, | | | Three Months Ended March 31, | |
Company | | 2010 | | | 2009 | | | 2010 | | | 2009 | | | 2011 | | 2010 | |
| | (in millions) | | | (in thousands) | |
APCo | | $ | 51 | | | $ | 50 | | | $ | 177 | | | $ | 146 | | | | $ | 44,941 | | | $ | 59,389 | |
CSPCo | | | 30 | | | | 31 | | | | 104 | | | | 91 | | | | | 26,045 | | | | 34,611 | |
I&M | | | 31 | | | | 32 | | | | 106 | | | | 93 | | | | | 31,827 | | | | 34,248 | |
OPCo | | | 41 | | | | 43 | | | | 153 | | | | 130 | | | | | 37,832 | | | | 49,104 | |
PSO | | | 23 | | | | 21 | | | | 78 | | | | 64 | | | | | 19,418 | | | | 23,736 | |
SWEPCo | | �� | 31 | | | | 35 | | | | 110 | | | | 94 | | | | | 29,833 | | | | 34,901 | |
The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows:
| | September 30, 2010 | | December 31, 2009 | | | March 31, 2011 | | December 31, 2010 |
| | As Reported in the | | Maximum | | As Reported in the | | Maximum | | | As Reported on the | | Maximum | | As Reported on the | | Maximum |
Company | | Balance Sheet | | Exposure | | Balance Sheet | | Exposure | | | Balance Sheet | | Exposure | | Balance Sheet | | Exposure |
| | (in millions) | | | (in thousands) |
APCo | | | $ | 18 | | | $ | 18 | | | $ | 23 | | | $ | 23 | | | $ | 15,653 | | $ | 15,653 | | $ | 23,230 | | $ | 23,230 |
CSPCo | | | | 10 | | | | 10 | | | | 13 | | | | 13 | | | 9,537 | | | 9,537 | | | 12,676 | | | 12,676 |
I&M | | | | 11 | | | | 11 | | | | 13 | | | | 13 | | | 10,823 | | | 10,823 | | | 12,980 | | | 12,980 |
OPCo | | | | 14 | | | | 14 | | | | 18 | | | | 18 | | | 12,959 | | | 12,959 | | | 16,927 | | | 16,927 |
PSO | | | | 6 | | | | 6 | | | | 9 | | | | 9 | | | 6,676 | | | 6,676 | | | 9,384 | | | 9,384 |
SWEPCo | | | | 11 | | | | 11 | | | | 14 | | | | 14 | | | 10,444 | | | 10,444 | | | 14,465 | | | 14,465 |
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. AEGCo leases 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. In the event AEGCo would require financing or other support outside the billings to I&M, CSPCo and KPCo, this fina ncingfinancing would be provided by AEP. For additional information regarding AEGCo’s lease, see the “Rockport Lease” section of Note 13 in the 20092010 Annual Report.
Total billings from AEGCo were as follows:
| | Three Months Ended September 30, | | Nine Months Ended September 30, | |
Company | | 2010 | | 2009 | | 2010 | | 2009 | |
| | (in millions) | |
CSPCo | | | $ | 44 | | | $ | 28 | | | $ | 81 | | | $ | 60 | |
I&M | | | | 64 | | | | 59 | | | | 168 | | | | 183 | |
| | Three Months Ended March 31, | |
Company | | 2011 | | 2010 | |
| | (in thousands) | |
CSPCo | | | $ | 51,034 | | | $ | 15,227 | |
I&M | | | | 52,821 | | | | 56,149 | |
The carrying amount and classification of variable interest in AEGCo’s accounts payable are as follows:
| | | |
| | September 30, 2010 | | December 31, 2009 | | | March 31, 2011 | | December 31, 2010 | |
| | As Reported in | | | | | As Reported in | | | | | | As Reported in | | | | | As Reported in | | | | |
| | the Consolidated | | Maximum | | the Consolidated | | Maximum | | | the Consolidated | | Maximum | | the Consolidated | | Maximum | |
Company | | Balance Sheet | | Exposure | | Balance Sheet | | Exposure | | | Balance Sheet | | Exposure | | Balance Sheet | | Exposure | |
| | (in millions) | | | (in thousands) | |
CSPCo | | | $ | 9 | | | $ | 9 | | | $ | 6 | | | $ | 6 | | | | $ | 19,035 | | | $ | 19,035 | | | $ | 18,165 | | | $ | 18,165 | |
I&M | | | | 28 | | | | 28 | | | | 23 | | | | 23 | | | | | 17,634 | | | | 17,634 | | | | 27,899 | | | | 27,899 | |
Related Party Transactions
SWEPCo Lignite Purchases from DHLC
Effective January 1, 2010, SWEPCo deconsolidated DHLC due to the adoption of new accounting guidance. See “ASU 2009-17 ‘Consolidations’ ” section of Note 2. DHLC sells 50% of its lignite mining output to SWEPCo and the other 50% to CLECO. SWEPCo purchased $40 million of lignite from DHLC and recorded these costs in Fuel on its Condensed Consolidated Balance Sheet at September 30, 2010.
AEP Power Pool Purchases from OVEC
In January 2010,March 2011, the AEP Power Pool began purchasing power from OVEC to serve off-system sales and retail sales through June 2010. Purchases serving off-system sales are reported net as a reduction in Electric Generation, Transmission and Distribution revenues and2011. These purchases serving retail sales are reported in Purchased Electricity for Resale expenses on the respective income statements. The following table shows the amounts recorded for the ninethree months ended September 30, 2010:March 31, 2011:
| | Nine Months Ended September 30, 2010 | | |
| | Reported in | | Reported in | | | Three Months Ended | |
Company | | Revenues | | Expenses | | | March 31, 2011 | |
| | (in thousands) | | | (in thousands) | |
APCo | | | $ | 6,631 | | | $ | 3,635 | | | | $ | 2,481 | |
CSPCo | | | | 3,689 | | | | 1,963 | | | | | 1,420 | |
I&M | | | | 3,721 | | | | 1,980 | | | | | 1,456 | |
OPCo | | | | 4,248 | | | | 2,268 | | | | | 1,704 | |
SWEPCo Revised Depreciation Rates
Effective December 2009 and May 2010, SWEPCo revised book depreciation rates for its Arkansas and Texas jurisdictions, respectively, as a result of base rate orders. In comparing 2010 and 2009, the change in depreciation rates resulted in a net decrease in depreciation expense of:
Total Depreciation Expense Variance |
Three Months Ended | | | Nine Months Ended |
September 30, 2010/2009 | | | September 30, 2010/2009 |
(in thousands) |
$ | 9,285 | | | $ | 19,718 |
Adjustments to Reported Cash Flows
In the Financing Activities section of SWEPCo’s Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2009, SWEPCo corrected the presentation of borrowings on lines of credit of $90 million from Change in Short-term Debt, Net – Nonaffiliated to Borrowings from Revolving Credit Facilities. SWEPCo also corrected the presentation of repayments on lines of credit of $92 million for the nine months ended September 30, 2009 to Repayments to Revolving Credit Facilities from Change in Short-term Debt, Net – Nonaffiliated. The correction to present borrowings and repayments on lines of credit on a gross basis was not material to SWEPCo’s financial statements and had no impact on SWEPCo’s previously reported net income, changes in shareholder’s equity, financial position or net cash flows from financing activities.
Adjustments to Sale of Receivables Disclosure
In the “Sale of Receivables – AEP Credit” section of Note 11, the disclosure was expanded for the Registrant Subsidiaries to reflect certain prior period amounts related to the sale of receivables that were not previously disclosed. These omissions were not material to the financial statements and had no impact on the Registrant Subsidiaries’ previously reported net income, changes in shareholder’s equity, financial position or cash flows.
Adjustments to Benefit Plans Footnote
In Note 65 – Benefit Plans, the disclosure was expanded for the Registrant Subsidiaries to reflect certain prior period amounts related to the Net Periodic Benefit Cost and the Estimated Future Benefit Payments and Contributions that were not previously disclosed. These omissions were not material to the financial statements and had no impact on the Registrant Subsidiaries’ previously reported net income, changes in shareholder’s equity, financial position or cash flows.
2. NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEM147
NEW ACCOUNTING PRONOUNCEMENTS
Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business. The following represents a summary of final pronouncements that impact the financial statements.
Pronouncements Adopted During 2010
The following standard was effective during the first nine months of 2010. Consequently, its impact is reflected in the financial statements. The following paragraphs discuss its impact.
ASU 2009-17 “Consolidations” (ASU 2009-17)
In 2009, the FASB issued ASU 2009-17 amending the analysis an entity must perform to determine if it has a controlling financial interest in a VIE. In addition to presentation and disclosure guidance, ASU 2009-17 provides that the primary beneficiary of a VIE must have both:
• The power to direct the activities of the VIE that most significantly impact the VIE’s economic performance.
• The obligation to absorb the losses of the entity that could potentially be significant to the VIE or the right
to receive benefits from the entity that could potentially be significant to the VIE.
The Registrant Subsidiaries adopted the prospective provisions of ASU 2009-17 effective January 1, 2010. This standard required separate presentation of material consolidated VIEs’ assets and liabilities on the balance sheets. Upon adoption, SWEPCo deconsolidated DHLC. DHLC was deconsolidated due to the shared control between SWEPCo and CLECO. After January 1, 2010, SWEPCo reports DHLC using the equity method of accounting.
EXTRAORDINARY ITEM
SWEPCo Texas Restructuring
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 May 2009, the governor of Texas signed a bill related to SWEPCo’s SPP area of Texas that requires continued cost of service regulation until certain stages have been completed and approved by the PUCT such that fair competition is available to all Texas retail customer classes. Based upon the signing of the bill, SWEPCo re-applied “Regulated Operations” accounting guidance for the generation portion of SWEPCo’s Texas retail jurisdiction effective second quarter of 2009. Management believes that a switch to competition in the SPP area of Texas will not occur. The reapplication of “Regulated Operations” accounting guidance resulted in an $8 million ($5 million, net of tax) extraordinary loss.
3.2. RATE MATTERS
As discussed in the 20092010 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 20092010 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 20102011 and updates the 20092010 Annual Report.
Regulatory Assets Not Yet Being Recovered
| | | | APCo | | I&M |
| | | | March 31, | | December 31, | | March 31, | | December 31, |
| | | | 2011 | | 2010 | | 2011 | | 2010 |
Noncurrent Regulatory Assets (excluding fuel) | | (in thousands) | | (in thousands) |
Regulatory assets not yet being recovered | | | | | | | | | | | | |
| pending future proceedings to determine | | | | | | | | | | | | |
| the recovery method and timing: | | | | | | | | | | | | |
Regulatory Assets Currently Not Earning a Return | | | | | | | | | | | | |
| Virginia Environmental Rate Adjustment Clause | | $ | 56,332 | | $ | 55,724 | | $ | - | | $ | - |
| Deferred Wind Power Costs | | | 33,636 | | | 28,584 | | | - | | | - |
| Storm Related Costs | | | 25,225 | | | 25,225 | | | - | | | - |
| Mountaineer Carbon Capture and Storage | | | | | | | | | | | | |
| | Product Validation Facility (b) | | | 19,249 | | | 59,866 | | | - | | | - |
| Special Rate Mechanism for Century Aluminum | | | 12,674 | | | 12,628 | | | - | | | - |
| Other Regulatory Assets Not Yet Being Recovered | | | 1,036 | | | 604 | | | - | | | - |
Total Regulatory Assets Not Yet Being Recovered | | $ | 148,152 | | $ | 182,631 | | $ | - | | $ | - |
| | | | | | | | | | | | | | |
| | | | CSPCo | | OPCo |
| | | | March 31, | | December 31, | | March 31, | | December 31, |
| | | | 2011 | | 2010 | | 2011 | | 2010 |
Noncurrent Regulatory Assets (excluding fuel) | | (in thousands) | | (in thousands) |
Regulatory assets not yet being recovered | | | | | | | | | | | | |
| pending future proceedings to determine | | | | | | | | | | | | |
| the recovery method and timing: | | | | | | | | | | | | |
Regulatory Assets Currently Earning a Return | | | | | | | | | | | | |
| Line Extension Carrying Costs (a) | | $ | 35,504 | | $ | 33,709 | | $ | 22,498 | | $ | 21,246 |
| Customer Choice Deferrals (a) | | | 29,911 | | | 29,716 | | | 29,314 | | | 29,141 |
| Storm Related Costs (a) | | | 19,366 | | | 19,122 | | | 11,161 | | | 11,021 |
| Acquisition of Monongahela Power (a) | | | 8,379 | | | 7,929 | | | - | | | - |
| Economic Development Rider | | | 3,100 | | | 3,057 | | | 3,100 | | | 3,057 |
| Other Regulatory Assets Not Yet Being Recovered | | | 289 | | | 287 | | | 393 | | | 391 |
Regulatory Assets Currently Not Earning a Return | | | | | | | | | | | | |
| Acquisition of Monongahela Power (a) | | | 4,052 | | | 4,052 | | | - | | | - |
| Other Regulatory Assets Not Yet Being Recovered | | | 46 | | | 43 | | | 61 | | | 58 |
Total Regulatory Assets Not Yet Being Recovered | | $ | 100,647 | | $ | 97,915 | | $ | 66,527 | | $ | 64,914 |
Regulatory Assets Not Yet Being Recovered | | | | | | | | | | | | |
| | | | APCo | | I&M |
| | | | September 30, | | December 31, | | September 30, | | December 31, |
| | | | 2010 | | 2009 | | 2010 | | 2009 |
| Noncurrent Regulatory Assets (excluding fuel) | | (in thousands) | | (in thousands) |
| Regulatory assets not yet being recovered pending | | | | | | | | | | | | |
| | future proceedings to determine the recovery | | | | | | | | | | | | |
| | method and timing: | | | | | | | | | | | | |
| Regulatory Assets Currently Earning a Return | | | | | | | | | | | | |
| | Customer Choice Implementation Costs | | $ | - | | $ | - | | $ | 6,650 | (a) | $ | 6,311 |
| Regulatory Assets Currently Not Earning a Return | | | | | | | | | | | | |
| | Mountaineer Carbon Capture and Storage Project | | | 59,144 | | | 110,665 | | | - | | | - |
| | Virginia Environmental Rate Adjustment Clause | | | 48,141 | | | 25,311 | | | - | | | - |
| | Storm Related Costs | | | 25,225 | | | - | | | - | | | - |
| | Deferred Wind Power Costs | �� | | 23,794 | | | 5,372 | | | - | | | - |
| | Virginia Transmission Rate Adjustment Clause | | | 21,088 | | | 26,184 | | | - | | | - |
| | Special Rate Mechanism for Century Aluminum | | | 12,578 | | | 12,422 | | | - | | | - |
| | Deferred PJM Fees | | | - | | | - | | | 7,200 | | | 6,254 |
| Total Regulatory Assets Not Yet Being Recovered | | $ | 189,970 | | $ | 179,954 | | $ | 13,850 | | $ | 12,565 |
| | | | | | | | | | | | | | |
| | | | CSPCo | | OPCo |
| | | | September 30, | | December 31, | | September 30, | | December 31, |
| | | | 2010 | | 2009 | | 2010 | | 2009 |
| Noncurrent Regulatory Assets (excluding fuel) | | (in thousands) | | (in thousands) |
| Regulatory assets not yet being recovered pending | | | | | | | | | | | | |
| | future proceedings to determine the recovery | | | | | | | | | | | | |
| | method and timing: | | | | | | | | | | | | |
| Regulatory Assets Currently Earning a Return | | | | | | | | | | | | |
| | Line Extension Carrying Costs | | $ | 31,915 | | $ | 26,590 | | $ | 19,993 | | $ | 16,278 |
| | Customer Choice Deferrals | | | 29,457 | | | 28,781 | | | 28,906 | | | 28,330 |
| | Storm Related Costs | | | 18,878 | | | 17,014 | | | 10,881 | | | 9,794 |
| | Acquisition of Monongahela Power | | | 7,483 | | | 10,282 | | | - | | | - |
| | Economic Development Rider | | | 3,014 | | | - | | | 3,014 | | | - |
| Regulatory Assets Currently Not Earning a Return | | | | | | | | | | | | |
| | Acquisition of Monongahela Power | | | 4,052 | | | - | | | - | | | - |
| | Peak Demand Reduction/Energy Efficiency | | | - | (b) | | 4,071 | | | - | (b) | | 4,007 |
| Total Regulatory Assets Not Yet Being Recovered | | $ | 94,799 | | $ | 86,738 | | $ | 62,794 | | $ | 58,409 |
| | | | | | | | | | | | | | |
| | | | PSO | | SWEPCo |
| | | | September 30, | | December 31, | | September 30, | | December 31, |
| | | | 2010 | | 2009 | | 2010 | | 2009 |
| Noncurrent Regulatory Assets (excluding fuel) | | (in thousands) | | (in thousands) |
| Regulatory assets not yet being recovered pending | | | | | | | | | | | | |
| | future proceedings to determine the recovery | | | | | | | | | | | | |
| | method and timing: | | | | | | | | | | | | |
| Regulatory Assets Currently Not Earning a Return | | | | | | | | | | | | |
| | Storm Related Costs | | $ | 17,256 | | $ | - | | $ | - | | $ | - |
| | Asset Retirement Obligation | | | - | | | - | | | 588 | | | 471 |
| Total Regulatory Assets Not Yet Being Recovered | | $ | 17,256 | | $ | - | | $ | 588 | | $ | 471 |
| | | | | | | | | | | | | | |
| (a) In October 2010, the Michigan base rate settlement agreement was approved which granted recovery of this regulatory asset. |
| (b) Recovery of regulatory asset was granted during 2010. |
| | | | | | | | | | | | | | |
| | | | PSO | | SWEPCo |
| | | | March 31, | | December 31, | | March 31, | | December 31, |
| | | | 2011 | | 2010 | | 2011 | | 2010 |
Noncurrent Regulatory Assets (excluding fuel) | | (in thousands) | | (in thousands) |
Regulatory assets not yet being recovered | | | | | | | | | | | | |
| pending future proceedings to determine | | | | | | | | | | | | |
| the recovery method and timing: | | | | | | | | | | | | |
Regulatory Assets Currently Not Earning a Return | | | | | | | | | | | | |
| Storm Related Costs | | $ | 17,256 | | $ | 17,256 | | $ | 1,239 | | $ | 1,239 |
| Other Regulatory Assets Not Yet Being Recovered | | | 533 | | | 574 | | | 676 | | | 613 |
Total Regulatory Assets Not Yet Being Recovered | | $ | 17,789 | | $ | 17,830 | | $ | 1,915 | | $ | 1,852 |
| | | | | | | | | | | | | | |
(a) | Requested to be recovered in a distribution asset recovery rider. See the "Ohio Distribution Base Rate Case" section below. |
(b) | APCo wrote off a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the WVPSC in March 2011. See "Mountaineer Carbon Capture and Storage Project Product Validation Facility" section below. |
CSPCo and OPCo Rate Matters
Ohio Electric Security Plan Filings
2009 – 2011 ESPs
The PUCO issued an order in March 2009 that modified and approved CSPCo’s and OPCo’s ESPs which established rates at the start of the April 2009 billing cycle. The ESPs are in effect through 2011. The order also limitslimited annual rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011. Some rate components and increases are exempt from these limitations. CSPCo and OPCo collected the 2009 annualized revenue increase over the last nine months of 2009.
The order providesprovided a FAC for the three-year period of the ESP. The FAC increase will bewas phased in to avoid having the resultant rate increases exceed the ordered annual caps described above. The FAC increase is subject to quarterly true-ups, annual accounting audits and prudency reviews. See the “2009 Fuel Adjustment Clause Audit” section below. The order allowsallowed CSPCo and OPCo to defer any unrecovered FAC costs resulting from the annual caps and to accrueaccrued associated carrying charges at CSPCo’s and OPCo’s weighted average cost of capital. Any deferred FAC regulatory asset balance at the end of the three-year ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018. That recovery will include deferrals asso ciatedassociated with the Ormet interim arrangement and is subject to the PUCO’s ultimate decision regarding the Ormet interim arrangement deferrals plus related carrying charges. See the “Ormet Interim Arrangement” section below. The FAC deferralsdeferral as of September 30, 2010 were $15March 31, 2011 was $19 million and $433$498 million for CSPCo and OPCo, respectively, excluding $2 million$77 thousand and $24$37 million, respectively, of unrecognized equity carrying costs.
Discussed below are the significant outstanding uncertainties related to the ESP order:
The Ohio Consumers’ Counsel filed a notice of appeal with the Supreme Court of Ohio raising several issues including alleged retroactive ratemaking, recovery of carrying charges on certain environmental investments, Provider of Last Resort (POLR) charges and the decision not to offset rates by off-system sales margins. A decision from the Supreme Court of Ohio is pending.
In November 2009, the Industrial Energy Users-Ohio (IEU) filed a notice of appeal with the Supreme Court of Ohio challenging components of the ESP order including the POLR charge, the distribution riders for gridSMARTSM® and enhanced reliability, the PUCO’s conclusion and supporting evaluation that the modified ESPs are more favorable than the expected results of a market rate offer, the unbundling of the fuel and non-fuel generation rate components, the scope and design of the fuel adjustment clause and the approval of the plan after the 150-day statutory deadline. A decision from
In April 2011, the Supreme Court of Ohio (the Court) issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged which resulted in three reversals, only two of which may have a prospective impact. First, the Court concluded that the PUCO's decision amounted to retroactive ratemaking. Since the pertinent revenues were collected in 2009 and the OCC did not successfully pursue the remedy of obtaining a
stay of the order prior to the revenues being collected, there is pending.no remand to the PUCO or refund to customers for this error. Second, the Court held that the PUCO's conclusion that the POLR charge is cost-based conflicted with the evidence and remanded the issue to the PUCO for further consideration. Third, the Court reversed the Order’s legal basis for a carrying charge associated with certain environmental investments and remanded that issue to the PUCO to determine whether an alternative legal basis supports the charge. If any rate changes result from the PUCO’s remand proceedings, such rate changes would be prospective from the date of the remand order through the remaining months of 2011.
In April 2010, the Industrial Energy Users-OhioIEU filed an additional notice of appeal with the Supreme Court of Ohio challenging alleged retroactive ratemaking, CSPCo's and OPCo's abilities to collect through the FAC amounts deferred under the Ormet interim arrangement and the approval of the plan after the 150-day statutory deadline. A decision from the Supreme Court of Ohio is pending.
In 2009, the PUCO convened a workshop to determine the methodology for the Significantly Excessive Earnings Test (SEET). Ohio law requires that the PUCO determine, following the end of each year of the ESP, if rate adjustments included in the ESP resulted in significantly excessive earnings. If the rate adjustments, in the aggregate, result in significantly excessive earnings, the excess amount could be returned to customers. The PUCO heard arguments related to various SEET issues including the treatment of the FAC deferrals. Management believes that CSPCo and OPCo should not be required to refund unrecovered FAC regulatory assets until they are collected, even assuming there are significantly excessive earnings in that year. In June 2010,January 2011, the PUCO issued an order re solving some of the SEET issues. The PUCO determined that the earnings of CSPCoon CSPCo’s and OPCo shall be calculated on an individual company basis and not on a combined CSPCo/OPCo basis. The PUCO ruled that many issues, including the treatment of deferrals and off-system sales, should be determined on a case-by-case basis. The PUCO’s decision on the SEET methodology is not expected to be finalized until after the PUCO issues an order on the SEET filings. In September 2010, CSPCo and OPCo filed theirOPCo’s 2009 SEET filings with the PUCO. CSPCo’s and OPCo’s returns on common equity were 20.84% and 10.81%, respectively, including off-system sales margins and 18.31% and 9.42%, respectively, excluding off-system sales margins. Included in the filings was CSPCo’s and OPCo’s determinationdetermined that the level at which their earned return on common equity may become significantly in excess of the average earned return on common equity of the comparable risk group of publicly traded firms was 22.51%. Based upon the methodology proposed by CSPCo and OPCo in the SEET filings, neither CSPCo’s nor OPCo’s 2009 return on common equity was significantly excessive. In October 2010, the PUCO staff filed testimony that recommended a return on common equity over 16.05% asearnings were not significantly excessive but did not address whether adjustments for off-system sales (OSS) and deferrals should be made to reduce the return. Also, in October 2010, intervenors, including the Ohio Consumers’ Counsel, filed testimony withdetermined relevant CSPCo earnings exceeded the PUCO recommending an acceptable return on common equity in the range of 11.58% to 13.58%determined threshold by 2.13%. As a result, the intervenors recommendedPUCO ordered CSPCo to refund up to $156$43 million ($28 million net of tax) of its 2009 earnings. Ifearnings to customers, which was recorded as a revenue provision on CSPCo’s December 2010 books. The PUCO ordered that the significantly excessive earnings be applied first to CSPCo’s FAC deferral, including unrecognized equity carrying costs, as of the date of the order, with any remaining balance to be credited to CSPCo’s customers on a per kilowatt basis. That credit began with the first billing cycle in February 2011 and will continue through December 2011. Several parties, including CSPCo and OPCo, filed requests for rehearing with the PUCO, determineswhich were denied in March 2011. CSPCo and OPCo are required to file their 2010 SEET filings with the PUCO in 2011. Based upon the approach in the PUCO 2009 order, management does not currently believe that CSPCo’s and/CSPCo or OPCo’s 2009 return on common equity wasOPCo will have any significantly excessive CSPCo and/or OPCo may be required to return a portion of their ESP revenues to customers.earnings in 2010.
Management is unable to predict the outcome of the various ongoing ESP proceedings and litigation discussed above. If these proceedings, including future SEET filings, result in adverse rulings, it could reduce future net income and cash flows and impact financial condition.
January 2012 – May 2014 ESP
In January 2011, CSPCo and OPCo filed an application with the PUCO to approve a new ESP that includes a standard service offer (SSO) pricing on a combined company basis for generation. The rates would be effective with the first billing cycle of January 2012 through the last billing cycle of May 2014. The ESP also includes alternative energy resource requirements and addresses provisions regarding distribution service, energy efficiency requirements, economic development, job retention in Ohio and other matters. The SSO presents redesigned generation rates by customer class. Customer class rates vary, but on average, customers will experience base generation increases of 1.4% in 2012 and 2.7% in 2013. The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESP could impact the outcome of the January 2012 – May 2014 ESP, though the nature and extent of that impact is not presently known.
Ohio Distribution Base Rate Case
In February 2011, CSPCo and OPCo filed with the PUCO for an annual increase in distribution rates of $34 million and $60 million, respectively. The requested increase is based upon an 11.15% return on common equity to be effective January 2012.
In addition to the annual increase, CSPCo and OPCo requested recovery of the projected December 31, 2012 balance of certain distribution regulatory assets of $216 million and $159 million, respectively, including approximately $102 million and $84 million, respectively, of unrecognized equity carrying costs. These assets would be recovered in a requested distribution asset recovery rider over seven years with additional carrying costs, beginning January 2013. The actual balance of these distribution regulatory assets as of March 31, 2011 was $98 million and $63 million for CSPCo and OPCo, respectively, excluding $57 million and $42 million of unrecognized equity carrying costs, respectively. If CSPCo and OPCo are not ultimately permitted to fully recover their deferrals, it would reduce future net income and cash flows and impact financial condition.
Proposed CSPCo and OPCo Merger
In October 2010, CSPCo and OPCo filed an application with the PUCO to merge CSPCo into OPCo. Approval of the merger will not affect CSPCo's and OPCo's rates until such time as the PUCO approves new rates, terms and conditions for the merged company. The merger is also subject to regulatory approval by the FERC.In January 2011, CSPCo and OPCo anticipate completionfiled an application with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo. CSPCo and OPCo requested the reorganization transaction be effective in October 2011. Decisions are pending from the PUCO and the FERC. Management is unable to predict the outcome of the merger during 2011.this proceeding.
Requested Sporn Unit 5 Shutdown and Proposed Distribution Rider
In October 2010, OPCo filed an application with the PUCO for the approval of a December 2010 closure of Sporn Unit 5 and the simultaneous establishment of a new non-bypassable distribution rider, outside the rate caps established in the 2009 – 2011 ESP proceeding. The proposed rider would recover the net book value of the unit as well as related materials and supplies as of December 2010, which iswas estimated to be $59 million, as well as future closure costs incurred after December 2010. OPCo also requested the PUCO to grant accounting authority to record the future closure costs as a regulatory asset or regulatory liability with a weighted average cost of capital carrying charge to be included in the proposed non-bypassable distribution rider after theythe costs are incurred. A lso in October 2010, OPCo filed a retirement notification with PJM pendingPending PUCO approval, of OPCo’s application to close Sporn Unit 5. Absent PUCO approval, management intends to operate Sporn Unit 5 through 2013.continues to operate. In April 2011, intervenors filed comments opposing OPCo’s application. A PUCO decision is pending as to whether a hearing will be ordered. Management is unable to predict the outcome of this proceeding.
2009 Fuel Adjustment Clause Audit
As required under the ESP orders, the PUCO selected an outside consultant to conduct the audit of the FAC for the period of January 2009 through December 2009. In May 2010, the outside consultant provided theirits confidential audit report of the FAC audit to the PUCO. The audit report included a recommendation that the PUCO should review whether any proceeds from a 2008 coal contract settlement agreement which totaled $72 million should reduce OPCo’s FAC under-recovery balance. Of the total proceeds, approximately $58 million was recognized as a reduction to fuel expense prior to 2009 and $14 million will reducewas recognized as a reduction to fuel expense in 2009 and 2010. Hearings were held in August 2010. Management is unable to predict the outcome of this proceeding. If the PUCO orders any portion of the $58 million previo uslypreviously recognized gains or potential otherany future adjustments be used to reduce the current year FAC deferral, it would reduce future net income and cash flows and impact financial condition.
Ormet Interim Arrangement
CSPCo, OPCo and Ormet, a large aluminum company, filed an application with the PUCO for approval of an interim arrangement governing the provision of generation service to Ormet. This interim arrangement was approved by the PUCO and was effective from January 2009 through September 2009. In March 2009, the PUCO approved a FAC in the ESP filings.filings and the FAC aspect of the ESP order was upheld by the Supreme Court’s April 2011 decision referenced in the “2009-2011 ESPs” section above. The approval of the FAC as part of the ESP, together with the PUCO approval of the interim arrangement, provided the basis to record regulatory assets for the difference between the approved market price and the rate paid by Ormet. Through September 2009, the last month of the interim arrangement, CSPCo and OPCo had $30 million and $34 million, respectively, of deferred FAC related to the interim arrangement including recog nizedrecognized carrying charges but excludingcharges. These amounts exclude $1 million and $1 million, respectively, of unrecognized equity carrying costs. In November 2009, CSPCo and OPCo requested that the PUCO approve recovery of the deferrals under the interim agreement plus a weighted average cost of capital carrying charge. The interim arrangement deferrals are included in CSPCo’s and OPCo’s FAC phase-in deferral balances. See “Ohio Electric Security Plan Filings” section above. In the ESP proceeding, intervenors requested that CSPCo and OPCo be required to refund the Ormet-related regulatory assets and requested that the PUCO prevent CSPCo and OPCo from collecting the Ormet-related revenues in the future. The PUCO did not take any action on this request in the 2009-2011 ESP proceeding. The intervenors raised the issue again in response to CSPCo’s and OPCo’s November 2009 filing to approve recovery of th ethe deferrals under the interim agreement.agreement and this issue remains pending before the PUCO. If CSPCo and OPCo are not ultimately permitted to fully recover their requested deferrals under the interim arrangement, it would reduce future net income and cash flows and impact financial condition.
Economic Development Rider
In April 2010, the Industrial Energy Users-OhioIEU filed a notice of appeal of the 2009 PUCO-approved Economic Development Rider (EDR) with the Supreme Court of Ohio. The EDR collects from ratepayers the difference between the standard tariff and lower contract billings to qualifying industrial customers, subject to PUCO approval. The Industrial Energy Users-OhioIEU raised several issues including claims that (a) the PUCO lost jurisdiction over CSPCo’s and OPCo’s ESP proceedings and related proceedings when the PUCO failed to issue ESP orders within the 150-day statutory deadline, (b) the EDR should not be exempt from the ESP annual rate limitations and (c) CSPCo and OPCo should not be allowed to apply a weighted average long-term debt carrying cost on deferred EDR regulatory assets. A decision from the Supreme Court of Ohio is pending.
In June 2010, Industrial Energy Users-Ohiothe IEU filed a notice of appeal of the 2010 PUCO-approved EDR with the Supreme Court of Ohio. The Industrial Energy Users-Ohio raisedOhio raising the same issues as noted in the 2009 EDR appeal plusappeal. In addition, the IEU added a claim that CSPCo and OPCo should not be able to take the benefits of the higher ESP rates while simultaneously challenging the ESP orders. A decision from the Supreme Court of Ohio is pending.
As of September 30, 2010,March 31, 2011, CSPCo and OPCo have incurred $39EDR costs of $48 million and $30$40 million, respectively, in EDR costs including carrying costs. Of these costs, CSPCo and OPCo have collected $2743 million and $20$33 million, respectively, through the EDR, which CSPCo and OPCo began collecting in January 2010. The remaining $12$5 million and $10$7 million for CSPCo and OPCo, respectively, are recorded as deferred EDR regulatory assets. If CSPCo and OPCo are not ultimately permitted to recover their deferrals or are required to refund EDR revenue collected, it would reduce future net income and cash flows and impact financial condition.
Environmental Investment Carrying Cost Rider
In February 2010, CSPCo and OPCo filed an application with the PUCO to establish an Environmental Investment Carrying Cost Rider to recover carrying costs for 2009 through 2011 related to environmental investments made in 2009. The carrying costs include both a return of and on the environmental investments as well as related administrative and general expenses and taxes. In August 2010, the PUCO issued an order approving a rider of approximately $26 million and $34 million for CSPCo and OPCo, respectively, effective September 2010. The implementation of the rider will likely not impact cash flows, but will increase the ESP phase-in plan deferrals associated with the FAC since this rider is subject to the rate increase caps authorized by the PUCO in the ESP proceedings.
Ohio IGCC Plant
In March 2005, CSPCo and OPCo filed a joint application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. Through September 30, 2010,March 31, 2011, CSPCo and OPCo have each collected $12 million in pre-construction costs authorized in a June 2006 PUCO order and each 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 before June 2011, allany pre-construction costs that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest. 160; Intervenors have filed motions with the PUCO requesting all pre-construction costs be refunded to Ohio ratepayers with interest. CSPCo and OPCo will not start construction of an IGCC plant until existing statutory barriers are addressed and sufficient assurance of regulatory cost recovery exists. Management cannot predict the outcome of any cost recovery litigation concerning the Ohio IGCC plant or what effect, if any, such litigation would have on future net income and cash flows. However, if CSPCo and OPCo were required to refund all or some of the pre-construction costs collected and the costs incurred were not recoverable in another jurisdiction, it would reduce future net income and cash flows and impact financial condition.
SWEPCo Rate Matters
Turk Plant
SWEPCo is currently constructing the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which is expected to be in service in 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and will operate the completed facility. The Turk Plant is currently estimated to cost $1.7 billion, excluding AFUDC, plus an additional $132125 million for transmission, excluding AFUDC. SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $132$125 million for transmission, excluding AFUDC. As of September 30, 2010,March 31, 2011, excluding costs attributable to its joint owners, SWEPCo has capitalized approximately $957 million$1.1 billion of expenditures (includin g(including AFUDC and capitalized interest of $121$156 million and related transmission costs of $58$73 million). As of September 30, 2010,March 31, 2011, the joint owners and SWEPCo have contractual construction commitments of approximately $339$260 million (including related transmission costs of $5$3 million). SWEPCo’s share of the contractual construction commitments is $249$191 million. If the plant is cancelled, the joint owners and SWEPCo would incur contractual construction cancellation fees, based on construction status as of September 30, 2010,March 31, 2011, of approximately $121$101 million (including related transmission cancellation fees of $1 million). SWEPCo’s share of the contractual construction cancellation fees would be approximately $89$74 million.
Discussed below are the significant outstanding uncertainties related to the Turk Plant:
The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the 88 MW SWEPCo Arkansas jurisdictional share of the Turk Plant. Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN. The Arkansas Supreme Court ultimately concluded that the APSC erred in determining the need for additional power supply resources in a proceeding separate from the proceeding in which the APSC granted the CECPN. However, the Arkansas Supreme Court approved the APSC’s procedure of granting CECPNs for transmission facilities in dockets separate from the Turk Plant CECPN proceeding. In June 2010, the Arkansas Supreme Court denied motions for rehearing filed by the APSC and SWEPCo. Therefore, SWEPCo filed a notice with the APSC of its intent to proceed with construction of the Turk Plant but that SWEPCo no longer intends to pursue a CECPN to seek recovery of the originally approved 88 MW portion of Turk Plant costs in Arkansas retail rates. In June 2010, the APSC issued an order which reversed and set aside the previously granted CECPN.
The PUCT issued an order approving a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected construction cost, excluding AFUDC and related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers. SWEPCo appealed the PUCT’s order contending the two cost cap restrictions are unlawful. The Texas Industrial Energy Consumers filed an appeal contending that the PUCT’s grant of a conditional CCN for the Turk Plant should be revoked because it was unnecessary to serve retail customers. In February 2010, the Texas District Court affirmed the PUCT’s order in all respects. In March 2010, SWEPCo and the Texas Industrial Energy Consumers appealed this decision to the Texas Court of Appeals. Management is unable to predict the timing of the outcome related to this proceeding.
The LPSC approved SWEPCo’s application to construct the Turk Plant. The Sierra Club petitioned the LPSC to begin an investigation into the construction of the Turk Plant which was rejected by the LPSC. The Sierra Club later refiled its petition as a stand alone complaint proceeding. SWEPCo filed a motion to dismiss and denied the allegations in the complaint. In October 2010, an Administrative Law Judge recommended the LPSC dismiss the complaint.
In November 2008, SWEPCo received its required air permit approval from the Arkansas Department of Environmental Quality and commenced construction at the site. The Arkansas Pollution Control and Ecology Commission (APCEC) upheld the air permit. In February 2010, theThe parties who unsuccessfully appealed the air permit to the APCEC filed a notice of appeal with the Circuit Court of Hempstead County, Arkansas. In December 2010, the Circuit Court affirmed the APCEC. In January 2011, the same parties filed a notice of appeal with the Arkansas Court of Appeals. A decision in that case is not likely before the third quarter of 2011.
TheA wetlands permit was issued by the U.S. Army Corps of Engineers in December 2009. In February 2010, the Sierra Club, the Audubon Society and others filed a complaint in the Federal District Court for the Western District of Arkansas against the U.S. Army Corps of Engineers challenging the process used and the terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts. In May 2010, plaintiffs filed with the Federal District Court for the Western District of Arkansas seekingimpacts, and sought a preliminary injunction to halt construction and for a temporary restraining order.
In July 2010, the Hempstead County Hunting Club also filed a complaint with the Federal District Court for the Western District of Arkansas against SWEPCo, the U.S. Army Corps of Engineers, the U.S. Department of the Interior and the U.S. Fish and Wildlife Service seeking a temporary restraining order and preliminary injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws. The plaintiffs'plaintiffs’ federal law claims challenge the process used and terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts. The plaintiffs'plaintiffs’ state law claims challenge SWEPCo's ability to construct the Turk Plant without obtaining a certificate from the APSC. This motion for preliminary injunction was heard simultaneously with the motion filed by the Sierra Club. In October 2010, the motions for preliminary injunction were partially granted. According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop. Mitigation measures required by the permit are authorized and may be completed. The preliminary injunction affects portions of the water intake and associated piping and portions of thetwo transmission lines. A hearing on SWEPCo’s appeal was held in March 2011. Management is unable to predict the timing of the outcome related to this proceeding. In October 2010, the Federal District Court certified issues relating to the state law claims to the Arkansas Supreme Court, including whether those claims are within the primary jurisdiction of the APSC. The Arkansas Supreme Court has yet to consideraccepted the request. In April 2011, legislation was passed in Arkansas that clarifies the scope of the certificate exemption and the APSC’s primary jurisdiction over the state law claims asserted in federal court. In response to the legislation, SWEPCo filed a notice of appeal withhas requested the Federal District Court of Appeals forto withdraw the Eighth Circuit and is seeking a stay of the preliminary injunction pend ing appeal.
In January 2009, SWEPCo was granted CECPNs by the APSC to build three transmission lines and facilities authorized by the SPP and needed to transmit power from the Turk Plant. Intervenors appealed the CECPN decisions in April 2009questions certified to the Arkansas Supreme Court of Appeals. In July 2010,and dismiss the Hempstead County Hunting Club and other appellants filed with the Arkansas Court of Appeals emergency motions to stay the transmission CECPNs to prohibit SWEPCo from taking ownership of private property and undertaking construction of the transmission lines. In July 2010, the Arkansas Court of Appeals issued a decision remanding all transmission line CECPN appeals to the APSC. As a result, a stay was not ordered and construction continues on the affected transmission lines. A hearing is scheduled for January 2011.state law claims.
Management expects that SWEPCo will ultimately be able to complete construction of the Turk Plant and related transmission facilities and place those facilities in service. However, if SWEPCo is unable to complete the Turk Plant construction, including the related transmission facilities, and place the Turk Plant in service or if SWEPCo cannot recover all of its investment in and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.
Stall Unit
SWEPCo constructed the Stall Unit, an intermediate load 500 MW natural gas-fired combustion turbine combined cycle generating unit, at its existing Arsenal Hill Plant located in Shreveport, Louisiana. The LPSC and the APSC issued orders capping SWEPCo’s Stall Unit construction costs at $445 million including AFUDC and excluding related transmission costs. The Stall Unit was placed in service in June 2010. As of September 30, 2010, the Stall Unit cost $423 million, including $49 million of AFUDC. Management does not expect the final costs of the Stall Unit to exceed the ordered cap. In July 2010, the Stall Unit was placed into Arkansas rates. SWEPCo received CWIP treatment for a portion of the Stall Unit in the 2009 Tex as Base Rate Filing. See “2009 Texas Base Rate Filing” section below. The Stall Unit will be phased into Louisiana rate base between October 2010 and October 2011.Louisiana Fuel Adjustment Clause Audit
Consultants for the LPSC issued their audit report of SWEPCo’s Louisiana retail FAC. The audit report included a significant recommendation that might result in a financial impact that could be material for SWEPCo. The audit report recommended that the LPSC discontinue SWEPCo’s tiered sharing mechanism related to off-system sales margins on a prospective basis and that SWEPCo included inappropriate costs in the FAC. In September 2010, the LPSC consultants filed testimony supporting their audit report findings but did not quantify their recommendations. Hearings are scheduled for January 2011. Management is unable to predict how the LPSC will rule on the recommendations in the audit report and its financial statement impact on net income, cash flows and financial condi tion.
2009 Texas Base Rate Filing
In August 2009, SWEPCo filed a rate case with the PUCT to increase its base rates by approximately $75 million annually including a return on common equity of 11.5%. The filing included requests for financing cost riders of $32 million related to construction of the Stall Unit and Turk Plant, a vegetation management rider of $16 million and other requested increases of $27 million. In April 2010,2011, a settlement agreement was approved byfiled with the PUCT to increase SWEPCo’s base rates by approximately $15 million annually, effective May 2010, including a return on common equity of 10.33%,LPSC which consists of $5 million related to construction of the Stall Unit and $10 millionresulted in other increases. In addition, thean immaterial impact for SWEPCo. The settlement agreement will decrease annual depreciat ion expense by $17 million and allows SWEPCo a $10 million one-year surcharge riderdeferred the off-system sales issue to recover additional vegetation management costs that SWEPCo must spend within two years.
Texas Fuel Reconciliation
In May 2010, various intervenors, includingSWEPCo’s upcoming formula rate plan (FRP) extension filing, which is expected to be filed in the PUCT staff, filed testimony recommending disallowances ranging from $3 million to $30 million in SWEPCo’s $755 million fuel and purchase power costs reconciliation for the period January 2006 through March 2009. In July 2010, Cities Advocating Reasonable Deregulation filed testimony regarding the 2007 transfersecond quarter of ERCOT trading contracts to AEPEP. Included in this testimony were unquantified refund recommendations relating to re-pricing of contract transactions.
In September 2010, the Administrative Law Judges issued a Proposal for Decision (PFD) that recommended a disallowance of a significant portion of the charges to a ten-year gas transportation agreement that began in 2009 for the Mattison Plant located in Northwest Arkansas. The PFD stated that SWEPCo should have pursued other transportation options or sought the supplier’s recourse rate2011. A decision from the FERC. The estimated recommended disallowance over the ten-year period through December 2018LPSC is $107 million for which the estimated Texas jurisdictional portion is $37 million. In addition, the PFD also contained recommendations to disallow risk premiums related to the ERCOT trading contracts transferred to AEPEP which are estimated to be $1.5 million on a Texa s retail jurisdictional basis. Through September 30, 2010, SWEPCo’s management estimated the impact of this PFD, if adopted by the PUCT, to be $7 million. In October 2010, SWEPCo filed exceptions on these issues with the PUCT. An order may be issued in the fourth quarter of 2010. Management is unable to predict the outcome of this reconciliation. If the PUCT disallows any portion of SWEPCo’s fuel and purchase power costs, it could reduce future net income and cash flows and possibly impact financial condition.pending.
Louisiana 2008 Formula Rate Filing
In April 2008, SWEPCo filed its first formula rate filing under an approved three-year formula rate plan (FRP).FRP. SWEPCo requested an increase in its annual Louisiana retail rates of $11 million to be effective in August 2008 in order to earn the approved formula return on common equity of 10.565%. In August 2008, as provided by the FRP, SWEPCo implemented the FRP rates, subject to refund. During 2009, SWEPCo recorded a provision for refund of approximately $1 million after reaching a settlement in principle with intervenors. ASWEPCo began refunding customers in August 2010. In March 2011, the LPSC approved the settlement stipulation was reached by the parties and is pending LPSC approval.
stipulation.
Louisiana 2009 Formula Rate Filing
In April 2009, SWEPCo filed the second FRP which would increase its annual Louisiana retail rates by an additional $4 million effective in August 2009. SWEPCo implemented the FRP rate increase as filed in August 2009, subject to refund. In October 2009, consultantsConsultants for the LPSC objected to certain components of SWEPCo’s FRP calculation. A settlement stipulation was reached by the parties and approved by the LPSC in March 2011. The settlement stipulation agreed to a $2 million refund, which was recorded in 2010 as a provision in Other Current Liabilities on SWEPCo's Condensed Consolidated Balance Sheets. SWEPCo is currentlyanticipates that the refund, with interest, will begin in settlement discussions. If a refund is required, it could reduce future net income and cash flows and impact financial condition.2011.
Louisiana 2010 Formula Rate Filing
In April 2010, SWEPCo filed the third FRP which would decrease its annual Louisiana retail rates by $3 million effective in August 2010 pursuant to the approved FRP, subject to refund. In October 2010, consultants for the LPSC objected to certain components of SWEPCo’s FRP calculations. Hearings are scheduled for September 2011. SWEPCo believes the rates as filed are in compliance with the FRP methodology previously approved by the LPSC. If the LPSC disagrees with SWEPCo, it could result in refunds which could reduce future net income and cash flows and impact financial condition.flows.
APCo Rate Matters
2009 Virginia Biennial Base Rate Case
In July 2009,March 2011, APCo filed a generation and distribution base rate increaserequest with the Virginia SCC to increase annual base rates by $126 million based upon an 11.65% return on common equity to be effective no later than February 2012. The return on common equity includes a requested 0.5% renewable portfolio standards incentive as allowed by law. APCo proposed to mitigate the requested base rate increase by $51 million by maintaining current depreciation rates until the next biennial filing. If approved, APCo’s net base rate increase would be $75 million.
Rate Adjustment Clauses
In 2007, the Virginia law governing the regulation of $154electric utility service was amended to, among other items, provide for rate adjustment clauses (RACs) beginning in January 2009 for the timely and current recovery of costs of (a) transmission services billed by an RTO, (b) demand side management and energy efficiency programs, (c) renewable energy programs, (d) environmental compliance projects and (e) new generation facilities, including major unit modifications. In March 2011, APCo filed for approval of an environmental RAC, a renewable energy program RAC and a generation RAC simultaneous with the 2011 Virginia base rate filing. The environmental RAC is requesting recovery of environmental compliance costs incurred from January 2009 through December 2010 of $38 million annually based on a 13.35% return on common equity. Interim rates, subjecttwo-year amortization. The renewable energy program RAC is requesting the incremental portion of deferred wind power costs for the Camp Grove and Fowler Ridge projects of $6 million. The generation RAC is requesting recovery of the Dresden Plant, currently under construction, which APCo has requested to refund, became effectivepurchase from AEGCo.
In accordance with Virginia law, APCo is deferring incremental environmental costs incurred after December 2008 and renewable energy costs incurred after August 2009 which are not being recovered in December 2009 but were discontinuedcurrent revenues. As of March 31, 2011, APCo has deferred $56 million of environmental costs (excluding $12 million of unrecognized equity carrying costs) and $34 million of renewable energy costs. APCo plans to seek recovery of non-incremental deferred wind power costs ($28 million as of March 31, 2011) in February 2010 when newly enacted Virginia legislation suspended the collection of interim rates. In July 2010,future rate proceedings. If the Virginia SCC issued an order approvingwere to disallow a $62 million increase based on a 10.53% return on common equity. The order denied recoveryportion of the Virginia share of the Mountaineer Carbon CaptureAPCo’s deferred costs, it would reduce future net income and Storage Project, which resulted in a pretax write-off of $54 million in the second quarter of 2010. See “Mountaineer Carbon Capture and Storag e Project” section below. In addition, the order allowed the deferral of approximately $25 million of incremental storm expense incurred in 2009. In July 2010, APCo filed with the Virginia SCC a petition for reconsideration of the order as it relates to the Mountaineer Carbon Capture and Storage Project which was denied in August 2010. Approximately $3 million, including interest, was refunded to customers in September 2010 related to the collection of interim rates.cash flows.
2010 West Virginia Base Rate Case
In May 2010, APCo filed a request with the WVPSC to increase APCo’s annual base rates by $140 million based onupon an 11.75% return on common equity to be effective March 2011. Hearings are scheduled for December 2010. A decision fromIn March 2011, the WVPSC is expectedmodified and approved a settlement agreement which increased annual base rates by approximately $46 million based upon a 10% return on common equity. The settlement agreement also resulted in Marcha pretax write-off of a portion of the Mountaineer Carbon Capture and Storage Product Validation Facility in the first quarter of 2011. See “Mountaineer Carbon Capture and Storage Project Product Validation Facility” section below. In addition, the WVPSC allowed APCo to defer and amortize $18 million of previously expensed 2009 incremental storm expenses and $14 million of costs that were previously expensed related to the 2010 cost reduction initiative, each over a period of seven years.
Mountaineer Carbon Capture and Storage Project
Product Validation Facility (PVF)
APCo and ALSTOM Power, Inc., an unrelated third party, jointly constructed a CO2 capture validation facility, which was placed into service in September 2009. APCo also constructed and owns the necessary facilities to store the CO2. In October 2009, APCo started injecting CO2 into the underground storage facilities. The injection of CO2 required the recording of an asset retirement obligation and an offsetting regulatory asset. Through September 30, 2010, APCo has recorded a noncurrent regulatory ass et of $59 million related to the Mountaineer Carbon Capture and Storage Project.
In APCo’s July 2009May 2010 West Virginia base rate filing, APCo requested recoveryrate base treatment of and a return on its Virginia jurisdictional share of its project costs andthe PVF, including recovery of the related asset retirement obligation regulatory asset amortization and accretion. In July 2010,March 2011, a WVPSC order denied the Virginia SCC issued arequest for rate base treatment of the PVF largely due to its experimental operation. The base rate order provided that denied recoveryshould APCo construct a commercial scale carbon capture and sequestration (CCS) facility, only the West Virginia portion of the Virginia sharePVF costs, based on load sharing among certain AEP operating companies, may be considered used and useful plant in service and included in future rate base. As a result, APCo recorded a pretax write-off of $41 million ($26 million net of tax) in the Mountaineer Carbon Capture and Storage Project costs.first quarter of 2011. See “2009“2010 West Virginia Base Rate Case” section above.
In APCo’s May 2010 West Virginia base rate filing, As of March 31, 2011, APCo requested recovery of andhas recorded a return on its West Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligationnoncurrent regulatory asset amortization and accretion.of $19 million related to the PVF. If APCo cannot recover its remaining investment in and accretion expenses related to the Mountaineer PVF, it would reduce future net income and cash flows.
Carbon Capture and StorageSequestration Project with the Department of Energy (DOE)
During 2010, AEPSC, on behalf of APCo, began the project definition stage for the potential construction of a new commercial scale CCS facility under consideration at the Mountaineer Plant. AEPSC, on behalf of APCo, applied for and was selected to receive funding from the DOE for the project. The DOE will fund 50% of allowable costs incurred for the CCS facility up to a maximum of $334 million. A Front-End Engineering and Design (FEED) study, scheduled for completion during the third quarter of 2011, will refine the total cost estimate for the CCS facility. Results from the FEED study will be evaluated by management before any decision is made to seek the necessary regulatory approvals to build the CCS facility. As of March 31, 2011, APCo has incurred $25 million in total costs and has received $7 million of DOE eligible funding resulting in a net $18 million balance included in Construction Work In Progress on the Condensed Consolidated Balance Sheets. If APCo is unable to recover the costs of the CCS project, it would reduce future net income and cash flows and impact financial condition.
flows.
APCo’s Filings for an IGCC Plant
APCo filed a petition with the WVPSC requesting approval of a Certificate of Public Convenience and Necessity (CPCN) to construct a 629 MW IGCC power plant in Mason County, West Virginia. APCo also requestedIn 2008, the Virginia SCC and the WVPSC to approveissued an order denying APCo’s request for a surcharge rate mechanism to provide for the timely recovery of pre-construction costs and the ongoing financing costs of the project during the construction period, as well as the capital costs, operating costs and a return on common equity once the facility is placed into commercial operation. The WVPSC granted APCo the CPCN and approved the requested cost recovery. Various intervenors filed petitions with the WVPSC to reconsider the order.
In 2008,order was based upon the Virginia SCC issued an order denying APCo’s request for a surcharge rate mechanism based upon itsSCC's finding that the estimated cost of the plant was uncertain and may escalate. The Virginia SCC also expressed concerns that the estimated costs did not include a retrofitting of carbon capture and sequestrationCCS facilities. During 2009, based on an unfavorablethe order received in Virginia, the WVPSC removed the IGCC case as an active case from its docket and indicated that the conditional CPCNCertificate of Environmental Compatibility and Public Need granted in 2008 must be reconsidered if and when APCo proceeds forward with the IGCC plant.
Through September 30, 2010,March 31, 2011, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $9$9 million applicable to its Virginia jurisdiction.
APCo will not start construction of the IGCC plant until sufficient assurance of full cost recovery exists in Virginia and in West Virginia. If the plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs. If the costs which, ifare not recoverable, it would reduce future net income and cash flows and impact financial condition.
APCo’s 2009 Expanded Net Energy Charge (ENEC) Filing
In September 2009, the WVPSC issued an order approving APCo’s March 2009 ENEC request. The approved order provided for recovery of an under-recovered balance plus a projected increase in ENEC costs over a four-year phase-in period with an overall increase of $320 million and a first-year increase of $112 million, effective October 2009. The WVPSC also approved a fixed annual carrying cost rate of 4%, effective October 2009, to be applied to the incremental deferred regulatory asset balance that will result from the phase-in plan and lowered annual coal cost projections by $27 million. As of September 30, 2010, APCo’s ENEC under-recovery balance was $365 million, excluding $1 million of unrecognized equity carrying costs, which is included in noncurrent regulatory assets.
In June 2010, the WVPSC approved a settlement agreement for $86 million, including $9 million of construction surcharges was filed with the WVPSC related to APCo’s second year ENEC increase. The settlement agreement provided for recovery of the amounts related to the renegotiated coal contracts and allows APCo to accrue a weighted average cost of capital carrying costscharge on the excess under-recovery balance due to the ENEC phase-in as adjusted for the impacts of Accumulated Deferred Income Taxes. In June 2010, the WVPSC approved the settlement agreement which madeThe new rates became effective in July 2010.
In March 2011, APCo filed its third year ENEC increase with the WVPSC to increase rates in July 2011 by $107 million, including a $19 million increase of construction surcharges, a $7 million increase of carrying charges and a $5 million decrease due to the discontinuation of the reliability surcharge. The requested increase in construction surcharges includes APCo’s West Virginia jurisdictional share of the requested purchase of the Dresden Plant, currently under construction, from AEGCo. Intervenors, including the WVPSC staff, filed a motion with the WVPSC to remove the Dresden Plant surcharge issue from this proceeding. As of March 31, 2011, APCo’s ENEC under-recovery balance was $374 million, excluding $6 million of unrecognized equity carrying costs, which is included in noncurrent regulatory assets. If the WVPSC were to disallow a portion of APCo’s deferred ENEC costs, it could reduce future net income and cash flows and impact financial condition.
WPCo Merger with APCo
In a November 2009 proceeding established by the WVPSC to explore options to meet WPCo's future power supply requirements, the WVPSC in November 2009, issued an order approving a joint stipulation among APCo, WPCo, the WVPSC staff and the Consumer Advocate Division. The order approved the recommendation of the signatories to the stipulation that WPCo merge into APCo and be supplied from APCo's existing power resources. Merger approvals from the WVPSC, Virginia SCC and the FERC are required. No merger approval filings have been made.
PSO Rate Matters
PSO Fuel and Purchased Power
2006 and Prior Fuel and Purchased Power
The OCC filed a complaint with the FERC related to the allocation of off-system sales margins (OSS) among the AEP operating companies in accordance with a FERC-approved allocation agreement. The FERC issued an adverse ruling in 2008. As a result, PSO recorded a regulatory liability in 2008 to return reallocated OSS to customers. Starting in March 2009, PSO refunded the additional reallocated OSS to its customers through February 2010.
A reallocation of purchased power costs among AEP West companies for periods prior to 2002 resulted in an under-recovery of $42 million of PSO fuel costs. PSO recovered the $42 million by offsetting it against an existing fuel over-recovery during the period June 2007 through May 2008. The Oklahoma Industrial Energy Consumers (OIEC) has contended that PSO should not have collected the $42 million without specific OCC approval. As such, the OIEC contends that the OCC should require PSO to refund the $42 million it collected through its fuel clause. The OCC has heard the OIEC appeal and a decision is pending. In March 2010, PSO filed motions to advance this proceeding since the FERC has ruled on the allocation of off-system sales margins and PSO has refunded the additional margins to its retail customers. If the OCC were to order PSO to refund all or a part of the $42 million, it would reduce future net income and cash flows and impact financial condition.
2008 Fuel and Purchased Power
In July 2009, the OCC initiated a proceeding to review PSO’s fuel and purchased power adjustment clause for the calendar year 2008 and also initiated a prudenceprudency review of the related costs. In March 2010, the Oklahoma Attorney General and the OIEC recommended the fuel clause adjustment rider be amended so that the shareholder’s portion of off-system sales margins decrease from 25% to 10%. The OIECOklahoma Industrial Energy Consumers also recommended that the OCC conduct a comprehensive review of all affiliate transactions during 2007 and 2008. In July 2010, additional testimony regarding the 2007 transfer of ERCOT trading contracts to AEPEP was filed. Included in thisThe testimony wereincluded unquantified refund recommendations relating to re-pricing of contract transactions. 0; A hearing is scheduled for January Hearings will likely occur in the second quarter of 2011. If the OCC were to issue an unfavorable decision, it could reduce future net income and cash flows and impact financial condition.
2008 Oklahoma Base Rate Appeal
In January 2009, the OCC issued a final order approving an $81 million increase in PSO’s non-fuel base revenues based on a 10.5% return on common equity. The new rates reflecting the final order were implemented with the first billing cycle of February 2009. PSO and intervenors filed appeals with the Oklahoma Supreme Court raising various issues. The Oklahoma Supreme Court assigned the case to the Court of Civil Appeals. In June 2010, the Court of Civil Appeals affirmed the OCC's decision. No parties sought rehearing or appeal and, as a result, this case has concluded.
2010 Oklahoma Base Rate Case
In July 2010, PSO filed a request with the OCC to increase annual base rates by $82 million, including $30 million that is currently being recovered through a rider. The requested net annual increase to ratepayers would be $52 million. The requested increase includes a $24 million increase in depreciation and an 11.5% return on common equity. In October 2010, various parties, including the OCC staff, filed testimony regarding PSO’s requested base rate increase. These parties proposed that PSO's request to increase depreciation rates be denied and that existing depreciation rates continue. PSO’s request to move the $30 million currently recovered through a rider to base rates was not opposed. The parties’ net annual rate recommendations ranged from a rate reduction of $18 million to an increase of less than $1 million based on a recommended return on common equity range from 9.5% to 10%. A hearing is scheduled for December 2010.I&M Rate Matters
Indiana Fuel Clause Filing (Cook Plant Unit 1 Fire and Shutdown)
I&M filed applications with the IURC to increase its fuel adjustment charge by approximately $53 million for the period of April 2009 through September 2009. The filings sought increases for previously under-recovered fuel clause expenses.
As fully discussed in the “Cook Plant Unit 1 Fire and Shutdown” section of Note 4, Cook Unit 1 (Unit 1) was shut down in September 2008 due to significant turbine damage and a small fire on the electric generator. Unit 1 was placed back into service in December 2009 at slightly reduced power. The unit outage resulted in increased replacement power fuel costs. The filing only requested the cost of replacement power through mid-December 2008, the date when I&M began receiving accidental outage insurance proceeds. I&M committed to absorb the remaining costs of replacement power through the date the unit returned to service, which occurred in December 2009.
I&M reached an agreement with intervenors, which was approved by the IURC in March 2009, to collect its existing prior period under-recovery regulatory asset deferral balance over twelve months instead of over six months as initially proposed. Under the agreement, the fuel factors were placed into effect, subject to refund, and a subdocket was established to consider issues relating to the Unit 1 shutdown including the treatment of the accidental outage insurance proceeds. I&M maintains a separate accidental outage policy with NEIL. In 2009, I&M recorded $185 million in revenue under the policy and reduced the cost of replacement power in customers’ bills by $78 million. In October 2010, the Indiana/Michigan Industrial Group and the Indiana Office of Utility Consumer Counselor filed testimony which recommended I&M pay to customers a portion of the accidental outage insurance proceeds up to the extent not previously paid to customers through the fuel adjustment clause or needed to cover costs not covered by I&M’s property damage insurance policy. Hearings are scheduled to be held in January 2011.
Management believes that I&M is entitled to retain the accidental outage insurance proceeds since it made customers whole regarding the replacement power costs. If any fuel clause revenues or accidental outage insurance proceeds have to be paid to customers, it would reduce future net income and cash flows and impact financial condition.
Michigan 2009 Power Supply Cost Recovery (PSCR) ReconciliationMichigan 2009 and 2010 Power Supply Cost Recovery (PSCR) Reconciliations (Cook Plant Unit 1 Fire and Shutdown) |
In March 2010, I&M filed its 2009 PSCR reconciliation with the MPSC. The filing included an adjustment to exclude from the PSCR the incremental fuel cost of replacement power due to the Cook Plant Unit 1 outage from mid-December 2008 through December 2009, the period during which I&M received and recognized the accidental outage insurance proceeds. Management believes thatIn October 2010, a settlement agreement was filed with the MPSC which included deferring the Unit 1 outage issue to the 2010 PSCR reconciliation. In March 2011, I&M is entitled to retainfiled its 2010 PSCR reconciliation with the accidental outage insurance proceeds since it made customers whole regarding the replacement power costs.MPSC. If any fuel clause revenues or accidental outage insurance proceeds have to be paid to customers, it would reduce future net income and cash flows and impact financial condition. See the “Cook Plant Unit 1 Fire and Shutdown” section of Note 4.3.
Michigan Base Rate Filing
In January 2010, I&M filed with the MPSC a request for a $63 million increase in annual base rates based on an 11.75% return on common equity. Starting with the August 2010 billing cycle, I&M, with the MPSC authorization, implemented a $44 million interim rate increase. The interim increase excluded new trackers and regulatory assets for which I&M was not currently incurring expenses. In October 2010, a settlement agreement was approved by the MPSC to increase annual base rates by $36 million based on a 10.35% return on common equity, effective December 2010, plus separate recovery of approximately $7 million of customer choice implementation costs over a t wo year period beginning April 2011. In addition, the approved revenue requirement includes the amortization of $6 million in previously expensed restructuring costs over five years, which I&M will defer and begin amortizing in the fourth quarter of 2010. Also, the approved settlement agreement provided for sharing of off-system sales margins between customers (75%) and I&M (25%) with customers receiving a credit in future Power Supply Cost Recovery proceedings for their jurisdictional share of any off-system sales margins. In September 2010, I&M recorded a provision for refund of $2 million, including interest, related to the implementation of interim rates.FERC Rate Matters
Regional Transmission Rate Proceedings at the FERC – Affecting APCo, CSPCo, I&M and OPCo
Seams Elimination Cost Allocation (SECA) Revenue Subject to Refund – Affecting APCo, CSPCo, I&M and OPCo |
In 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 2006. Intervenors objected to the temporary SECA rates. The FERC set SECA rate issues for hearing and ordered that the SECA rate revenues be collected, subject to refund. The AEP East companies recognized gross SECA revenues of $220 million from 2004 through 2006 when the SECA rates terminated leaving the AEP East companies and ultimately their internal load retail customers to make up the shortfall in revenues.terminated. APCo’s, CSPCo’s, I&M’s and OPCo’s portions of recogn izedrecognized gross SECA revenues are as follows:
Company | | (in millions) | |
APCo | | $ | 70.2 | |
CSPCo | | | 38.8 | |
I&M | | | 41.3 | |
OPCo | | | 53.3 | |
In 2006, a FERC Administrative Law Judge (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 any unpaid SECA rates must be paid in the recommended reduced amount.
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 May 2010, the FERC issued an order that generally supports AEP’s position and requires a compliance filing to be filed with the FERC by August 2010. In June 2010, AEP and other affected companies filed a joint request for rehearing with the FERC regarding certain matters including a request to clarify the method for determining the amount of such revenues. The request also asked the FERC to clarify that interest may be added to SECA charges originally billed to but never paid by Green Mountain Energy (reassigned to British Petroleum Energy). Eight other groups also filed requests for rehearing with the FERC.
The AEP East companies provided reserves for net refunds for SECA settlements totaling $44 million applicable to the $220 million of SECA revenues collected. APCo’s, CSPCo’s, I&M’s and OPCo’s portions of the provision are as follows:
Company | | (in millions) | |
APCo | | $ | 14.1 | |
CSPCo | | | 7.8 | |
I&M | | | 8.3 | |
OPCo | | | 10.7 | |
Settlements approved by the FERC consumed $10 million of the reserve for refunds applicable to $112 million of SECA revenue. In December 2010, the FERC issued an order approving a settlement agreement resulting in the collection of $2 million of previously deemed uncollectible SECA revenue. Therefore, the AEP East companies reduced their reserves for net refunds for SECA settlements by $2 million. The balance in the reserve for future settlements as of September 30, 2010March 31, 2011 was $34$32 million. APCo’s, CSPCo’s, I&M’s and OPCo’s reserve balances at September 30, 2010as of March 31, 2011 were:
Company | | September 30, 2010 | | | March 31, 2011 | |
| | (in millions) | | | (in millions) | |
APCo | | $ | 10.7 | | | $ | 10.0 | |
CSPCo | | | 5.9 | | | | 5.6 | |
I&M | | | 6.3 | | | | 5.9 | |
OPCo | | | 8.1 | | | | 7.6 | |
In August 2010, the affected companies, including the AEP East companies, filed a compliance filing with the FERC. If the compliance filing is accepted, the AEP East companies would have to pay refunds of approximately $20 million including estimated interest of $5 million. The AEP East companies could also potentially receive payments up to approximately $12$10 million including estimated interest of $3$3 million. A decision is pending from the FERC. APCo’s, CSPCo’s, I&M’s and OPCo’s portions of potential refund payments and potential payments to be received are as follows:
Company | | Potential Refund Payments | | | Potential Payments Received | | | Potential Refund Payments | | | Potential Payments to be Received | |
| | (in millions) | | | (in millions) | |
APCo | | $ | 6.4 | | | $ | 3.8 | | | $ | 6.4 | | | $ | 3.2 | |
CSPCo | | | 3.5 | | | | 2.1 | | | | 3.5 | | | | 1.8 | |
I&M | | | 3.7 | | | | 2.2 | | | | 3.7 | | | | 1.9 | |
OPCo | | | 4.8 | | | | 2.9 | | | | 4.8 | | | | 2.4 | |
Based on the AEP East companies’ analysis of the May 2010 order and the compliance filing, management believes that the reserve is adequate to pay the refunds, including interest, that will be required should the May 2010 order or the compliance filing be made final. Management cannot predict the ultimate outcome of this proceeding at the FERC which could impact future net income and cash flows.
Allocation of Off-system Sales Margins – Affecting SWEPCo158
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.Possible Termination of the Interconnection Agreement – Affecting APCo, CSPCo, I&M and OPCo |
In 2009, AEP made a compliance filing with the FERC andDecember 2010, each of the AEP East companies refunded approximately $250 millionPower Pool members gave notice to AEPSC and each other of their decision to terminate the Interconnection Agreement effective January 2014 or such other date approved by FERC, subject to state regulatory input. No filings have been made at the FERC. It is unknown at this time whether the AEP West companies. Following authorized regulatory treatment,Power Pool will be replaced by a new agreement among some or all of the members, whether individual companies will enter into bilateral or multi-party contracts with each other for power sales and purchases or asset transfers or if each company will choose to operate independently. This decision to terminate is subject to management’s ongoing evaluation. The AEP Power Pool members may revoke their notices of termination. If any of the AEP West companies sharedPower Pool members experience decreases in revenues or increases in costs as a portionresult of SIA margins with their customers during the period June 2000 to March 2006. In 2008,termination of the AEP West companies recorded a provision for refund reflecting the sharing. Refunds have been orPower Pool and are currently being returned to PSO, SWEPCo and FERC customers. Management believes the AEP West companies’ provision for refund is adequate.
Modification of the Transmission Agreement (TA) – Affecting APCo, CSPCo, I&M and OPCo
APCo, CSPCo, I&M, KPCo and OPCo are parties to the TA that provides for a sharing of the cost of transmission lines operated at 138-kV and above and transmission stations containing extra-high voltage facilities. In June 2009, AEPSC, on behalf of the parties to the TA, filed with the FERC a request to modify the TA. Under the proposed amendments, KGPCo and WPCo will be added as parties to the TA. In addition, the amendments would provide for the allocation of PJM transmission costs on the basis of the TA parties’ 12-month coincident peak and reimburse transmission revenues based on individual cost of service instead of the MLR method used in the present TA. AEPSC requested the effective date to be the first day of the month following a final non-appealable FERC order. T he delayed effective date was approved by the FERC when the FERC accepted the new TA for filing. In August 2010, a settlement agreement was filed with the FERC. In October 2010, the FERC approved the new TA effective November 1, 2010. The impacts of the settlement agreement will be phased-in for retail rate making purposes in certain jurisdictions over periods of up to four years. However, management is unable to predict whetherrecover the parties to the TA will experience regulatory lagchange in revenues and its effect oncosts through rates, prices or additional sales, it could reduce future net income and cash flows.
PJM Transmission Formula Rate Filing – Affecting APCo, CSPCo, I&M and OPCo
AEP filed an application with the FERC in July 2008 to increase its open access transmission tariff (OATT) rates for wholesale transmission service within PJM. The filing sought to implement a formula rate allowing annual adjustments reflecting future changes in the AEP East companies' cost of service. The FERC issued an order conditionally accepting AEP’s proposed formula rate and delayed the requested October 2008 effective date for five months. AEP began settlement discussions with the intervenors and the FERC staff which resulted in a settlement that was filed with the FERC in April 2010.
The pending settlement results in a $51 million annual increase beginning in April 2009 for service as of March 2009, of which approximately $7 million is being collected from nonaffiliated customers within PJM. The remaining $44 million is being billed to the AEP East companies and is generally offset by compensation from PJM for use of the AEP East companies’ transmission facilities so that net income is not directly affected.
The pending settlement also results in an additional $30 million increase for the first annual update of the formula rate, beginning in August 2009 for service as of July 2009. Approximately $4 million of the increase will be collected from nonaffiliated customers within PJM with the remaining $26 million being billed to the AEP East companies.
Under the formula, an annual update will be filed to be effective July 2010 and each year thereafter. Also, beginning with the July 2010 update, the rates each year will include an adjustment to true-up the prior year's collections to the actual costs for the prior year. In May 2010, the second annual update was filed with the FERC to decrease the revenue requirement by $58 million for service as of July 2010. Approximately $8 million of the decrease will be refunded to nonaffiliated customers within PJM. In October 2010, the settlement agreement was approved by the FERC.
Transmission Agreement (TA) – Affecting APCo, CSPCo, I&M and OPCo
Certain transmission facilities placed in service in 1998 were inadvertently excluded from the AEP East companies’ TA calculation prior to January 2009. The excluded equipment was KPCo’s Inez Station which had been determined as eligible equipment for inclusion in the TA in 1995 by the AEP TA transmission committee. The amount involved was $7 million annually. In June 2010, the KPSC approved a settlement agreement in KPCo’s base rate filing which set new base rates effective July 2010 but excluded consideration of this issue.
PJM/MISO Market Flow Calculation Settlement Adjustments - Affecting APCo, CSPCo, I&M and OPCo
During 2009, an analysis conducted by MISO and PJM discovered several instances of unaccounted for power flows on numerous coordinated flowgates. These flows affected the settlement data for congestion revenues and expenses and datedated back to the start of the MISO market in 2005. In January 2011, PJM hasand MISO reached a settlement agreement where the parties agreed to net various issues to zero. This settlement was filed with the FERC in January 2011. PJM and MISO are currently awaiting final approval from the FERC.
Modification of the Transmission Coordination Agreement (TCA) – Affecting PSO and SWEPCo
PSO, SWEPCo and TNC are parties to the TCA, originally dated January 1, 1997, as amended. The TCA provides for the allocation among the parties of revenues collected for transmission and ancillary services provided MISO an initial analysis of amounts they believe they owe MISO. MISO disputes PJM’s methodology.under the OATT.
Settlement discussions between MISO and PJM have been unsuccessful, and as a result, in March 2010, MISO filed two related complaints against PJM atIn April 2011, the FERC relatedaccepted proposed revisions to the above claim. MISO seeks to recover a totalTCA. Under this amendment, TNC was removed from the TCA. In addition, the amended TCA provides for the allocation of approximately $145 million from PJM. If PJMSPP OATT revenues between PSO and SWEPCo based on the SPP formula rate revenue requirements for transmission investment and related expenses of each company. The amended TCA is held liable for these damages, PJM members, including the AEP East companies, may be billed for a share of the refunds or payments PJM is directed to make to MISO. AEP has intervened and filed a protest to one complaint. Management believes that MISO's claims are without merit and that PJM's right to recover any MISO damages from AEP and other members is limited. If the FERC orders a settlement above the AEP East companies’ reserve related to their estimated portion of PJM additional costs, it could reduce future net income and cash flows and impact financial condition.effective May 1, 2011.
4.3. 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 20092010 Annual Report should be read in conjunction with this report.
GUARANTEES
Liabilities for guarantees are recorded in accordance with the accounting guidance for “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 with third parties. These letters of credit are issued in the ordinary course of business and cover items such as insurance programs, security deposits and debt service reserves. These letters of credit were issued in the ordinary course of business under the
AEP has two $1.5 billion credit facilities, ofunder which $750 millionup to $1.35 billion may be issued under one credit facility as letters of credit. In June 2010, AEP terminated one of the $1.5 billion facilities that was scheduled to mature inAt March 31, 2011, and replaced it with a new $1.5 billion credit facility which matures in 2013 and allows for the issuance of up to $600 million as letters of credit.
In June 2010, the Registrant Subsidiaries and certain other companies in the AEP System reduced the $627 million credit agreement to $478 million. As of September 30, 2010, $477 million of letters of credit were issued by Registrant Subsidiaries under the agreement to support variable rate Pollution Control Bonds.
At September 30, 2010, the maximum future payments of the letters of credit were as follows:
| | | | | | | Borrower |
Company | | Amount | | Maturity | | Sublimit |
| | (in thousands) | | | | (in thousands) |
$1.5 billion letters of credit: | | | | | | | | |
I&M | | $ | 300 | | March 2011 | | | N/A |
SWEPCo | | | 4,448 | | December 2010 | | | N/A |
| | | | | | | | |
$478 million letter of credit: | | | | | | | | |
APCo | | $ | 232,292 | | November 2010 to April 2011 | | $ | 300,000 |
I&M | | | 77,886 | | April 2011 | | | 230,000 |
OPCo | | | 166,899 | | April 2011 | | | 400,000 |
Company | | Amount | | Maturity |
| | | (in thousands) | | |
$1.35 billion letters of credit: | | | | | |
| I&M | | $ | 150 | | March 2012 |
| SWEPCo | | | 4,448 | | June 2011 |
In March 2011, the Registrant Subsidiaries and certain other companies in the AEP System terminated a $478 million credit agreement that was scheduled to mature in April 2011 and was used to support variable rate Pollution Control Bonds. In March 2011, certain variable rate Pollution Control Bonds were remarketed and supported by bilateral letters of credit for $361 million while others were reacquired and are being held in trust. As of March 31, 2011, $472 million of variable rate Pollution Control Bonds were remarketed or reacquired as follows:
| | March 31, 2011 |
| | | | | Reacquired | | Bilateral | | Maturity of |
| | | | | and Held | | Letters of | | Bilateral Letters |
Company | | Remarketed | | in Trust | | Credit Issued | | of Credit |
| | (in thousands) | | |
APCo | | | $ | 229,650 | | | $ | - | | | $ | 232,293 | | March 2013 to March 2014 |
I&M | | | | 77,000 | | | | - | | | | 77,886 | | March 2013 |
OPCo | | | | 50,000 | | | | 115,000 | | | | 50,575 | | March 2013 |
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 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), a consolidated variable interest entity. 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 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million. As of September 30, 2010,March 31, 2011, SWEPCo has collected approximately $47$50 million through a rider for final mine closure and reclamati onreclamation costs, of which $1 million is recorded in Other Current Liabilities, $23$26 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $23 million is recorded in Asset Retirement Obligations 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
The 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, 2010, the Registrant Subsidiaries entered intoThe status of certain sale agreements including indemnifications with a maximum exposure that was not significant for any individual Registrant Subsidiary. Thereis discussed in the 2010 Annual Report “Dispositions” section of Note 7. As of March 31, 2011, 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 Lease Agreements
The Registrant Subsidiaries lease certain equipment under master lease agreements. In December 2010, management signed a new master lease agreement with 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 2011, the Registrant Subsidiaries will be required to purchase all equipment under the lease and pay GE an amount equal to the unamortized value of all equipment then leased. Management is currently in negotiations to replace this agreement. In December 2008existing operating and 2009, management signed newcapital leases with GE. These assets were included in existing master lease agreements that include lease terms of upwere to 10 years.be terminated in 2011 since GE exercised the termination provision related to these leases in 2008. Certain assets were not included in the refinancing in 2010, but the remaining assets were purchased in January 2011.
For equipment under the GE master lease agreements, that expire in 2011, the lessor is guaranteed receipt of up to 87%78% of the unamortized balance of the equipment at the end of the lease term. If the fair 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 fair value and the unamortized balance, with the total guarantee not to exceed 87%78% of the unamortized balance. Under the newFor equipment under other master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrant Su bsidiariesSubsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee. At September 30, 2010,March 31, 2011, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows:
| | Maximum | | |
| | Potential | | |
Company | | Loss | | | | |
| | (in thousands) | | | (in thousands) | |
APCo | | | $ | 294 | | | | $ | 1,320 | |
CSPCo | | | | 70 | | | | | 949 | |
I&M | | | | 181 | | | | | 1,782 | |
OPCo | | | | 411 | | | | | 1,262 | |
PSO | | | | 323 | | | | | 665 | |
SWEPCo | | | | 231 | | | | | 2,652 | |
Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.
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 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 renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $18$17 million f orfor I&M and $20$19 million for SWEPCo for the remaining railcars as of September 30, 2010.March 31, 2011.
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 from approximately 84% under the current five year lease term to 77% at the end of the 20 year20-year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. I&M’s maximum potential loss related to the guarantee is approximately $12 million ($8 million, net of tax) and SWEPCo’s is approximately $13 million ($9 million, net of tax) assuming the fair value of the equipment is zero at the end of the current five-year lease term. However, management believes that the fair 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.161
ENVIRONMENTAL 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&M and OPCo modified certain units at their coal-fired generating plants in violation of the NSR requirements of the CAA. Cases with similar allegations against CSPCo, Dayton Power and Light Company and Duke Energy Ohio, Inc. were also filed related to their jointly-owned units. The cases were settled with the exception of a case involving a jointly-owned Beckjord unit which had a liability trial. Following the trial, the jury found no liability for claims made against the jointly-owned Beckjord unit. Following a second liability trial in 2009, the jury again found no liability at the jointly-owned Beckjord unit. The defendants and the plaintiffs appealed to the Seventh Circuit Court of Appeals. In October 2010, the Seventh Circuit dismissed all of the remaining claims in these cases. Beckjord is operated by Duke Energy Ohio, Inc.
Notice of Enforcement and Notice of Citizen Suit – Affecting SWEPCo
In 2005, two special interest groups, Sierra Club and Public Citizen, filed a complaint alleging violations of the CAA at SWEPCo’s Welsh Plant. In 2008, a consent decree resolved all claims in the case and in the pending appeal of an altered permit for the Welsh Plant. The consent decree required SWEPCo to install continuous particulate emission monitors at the Welsh Plant, secure 65 MW of renewable energy capacity, fund $2 million in emission reduction, energy efficiency or environmental mitigation projects and pay a portion of plaintiffs’ attorneys’ fees and costs.
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 a previous state permit. The NOV also alleges that a permit alteration issued by the Texas Commission on Environmental Quality in 2007 was improper. In March 2008, SWEPCo met with the Federal EPA to discuss the alleged violations. 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. Management is unable to determine a range of potential losses that are reasonably possible of occurring.
Carbon Dioxide Public Nuisance Claims – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo
In 2004, eight states and the City of New York filed an action in Federal District Court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennessee Valley Authority (TVA).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 trial court dismissed the lawsuits.
In September 2009, the Second Circuit Court of Appeals issued a ruling on appeal remanding the cases to the Federal District Court for the Southern District of New York. The Second Circuit held that the issues of climate change and global warming do not raise political questions and that Congress’ refusal to regulate CO2 emissions does not mean that plaintiffs must wait for an initial policy determination by Congress or the President’s administration to secure the relief sought in their complaints. The court stated that Congress could enact comprehensive legislation to regulate CO2 emissions or that the Federal EPA could regulate CO2 emissions under existing CAA authorities and that either of these actions could override any decision made by the district court under federal common law. The Second Circuit did not rule on whether the plaintiffs could proceed with their state common law nuisance claims. TheIn December 2010, the defendants’ petition for rehearingreview by the U.S. Supreme Court was denied.granted. The case was heard in April 2011. Management believes the actions are without merit and intends to continue to defend against the claims. The defendants, excluding TVA, filed a petition for review with the U.S. Supreme Court in August 2010. The Solicitor General filed a brief in support of the petition on behalf of TVA. Responses to the petition are due in November 2010.
In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina. The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs’ complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims. The court granted petitions for rehearing. An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court& #8217;scourt’s decision in place. The Registrant Subsidiaries were initially dismissed from this case without prejudice, but are named as defendants in a pending fourth amended complaint. Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision. Responses to theThe petition are duewas denied in November 2010.January 2011.
Management is unable to determine a range of potential losses that are reasonably possible of occurring.
Alaskan Villages’ Claims – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo
In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and 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. In October 2009, the judge dismissed plaintiffs’ federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs’ lack of standing to bring the claim. The judge also dismissed plaintiffs’ state law claims without prejudice to refiling in state court. The plaintiffs appealed the decision. Briefing is complete and no date has been set for oral argument. The defendants requested that the court defer setting this case for oral argument until after the Supreme Court issues its decision in the CO2 public nuisance case discussed above. The court entered an order deferring argument until after June 2011. Management believes the action is without merit and intends to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring.
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 and other hazardous and nonhazardous materials. The Registrant Subsidiaries currently incur costs to dispose of these substances safely.
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. In May 2008, I&M started remediation work in accordance with a plan approved by MDEQ. I&M recorded&M’s provision is approximately $11 million of expense prior to January 1, 2010, $3 million of which I&M recorded in March 2009.million. As the remediation work is completed, I&M’s cost may continue to increase as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ. Management cannot predict the amount of additional cost, if any.
Amos Plant – State and Federal Enforcement Proceedings – Affecting APCo and OPCo
In March 2010, APCo and OPCo received a letter from the West Virginia Department of Environmental Protection, Division of Air Quality (DAQ), alleging that at various times in 2007 through 2009 the units at Amos Plant reported periods of excess opacity (indicator of compliance with particulate matterPM emission limits) that lasted for more than thirty30 consecutive minutes in a 24-hour period and that certain required notifications were not made. Management met with representatives of DAQ to discuss these occurrences and the steps taken to prevent a recurrence. DAQ indicated that additional enforcement action may be taken, including imposition of a civil penalty of approximately $240 thousand. APCo and OPCo denied that violations of the reporting requirements occurred and maintain that the proper reporting was done. Management continues to discuss the resolution ofIn March 2011, APCo and OPCo resolved these issues with DAQ, but cannot predictthrough the outcomeentry of these discussions ora consent order that included the amountpayment of anya $75 thousand civil penalty that may be assessed.and certain improvements in the opacity reports.
In March 2010, APCo and OPCo received a request to show cause from the Federal EPA alleging that certain reporting requirements under Superfund and the Emergency Planning and Community Right-to-Know Act had been violated and inviting APCo and OPCo to engage in settlement negotiations. The request includes a proposed civil penalty of approximately $300 thousand. Management indicated a willingness to engage in good faith negotiations and provided additional information to representatives of the Federal EPA. Management has not admitted that any violations occurred or that the amount of the proposed penalty is reasonable.
Management is unable to determine a range of potential losses that are reasonably possible of occurring.
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 jet bubbling reactor (JBR) technology. The retrofits on two Cardinal Plant units and a Conesville Plant unit are operational. Contracts for other projects were suspended during their early development stages. Due to unexpected operating results, management completed an extensive review in 2009 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. In August 2010, management signed a settlement agreement with Black & Veatch that resolved the issues involving the internal components. Management also reached an agreement in principle regarding JBR vessel corrosion issues. These settlements result in an immaterial increase in the capitalized costs of the projects for modification of the scope of the contracts.
NUCLEAR CONTINGENCIES – AFFECTING I&M
I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generating units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.
Cook Plant Unit 1 Fire and Shutdown
In September 2008, I&M shut down Cook Plant Unit 1 (Unit 1) due to turbine vibrations, caused by blade failure, which resulted in significant turbine damage and a small fire on the electric generator. This equipment, located in the turbine building, is separate and isolated from the nuclear reactor. The turbine rotors that caused the vibration were installed in 2006 and are within the vendor’s warranty period. The warranty provides for the repair or replacement of the turbine rotors if the damage was caused by a defect in materials or workmanship. Repair of the property damage and replacement of the turbine rotors and other equipment could cost up to approximately $395 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. I&M repaired Unit 1 and it resumed operations in December 2009 at slightly reduced power. The Unit 1 rotors were repaired and reinstalled due to the extensive lead time required to manufacture and install new turbine rotors. As a result, the replacement of the repaired turbine rotors and other equipment is scheduled for the Unit 1 planned outage in the fall of 2011.
I&M maintains property insurance through NEIL with a $1 million deductible.NEIL. As of September 30, 2010,March 31, 2011, I&M recorded $53$47 million on its Condensed Consolidated Balance Sheet representing recoverable amounts under the propertyNEIL insurance policy. Through September 30, 2010,March 31, 2011, I&M received partial payments of $203 million from NEIL for the cost incurred to date to repair the property damage.
I&M also maintains a separate accidental outage policy with NEIL. In 2009, I&M recorded $185 million in revenue under the policy and reduced the cost of replacement power in customers’ bills by $78 million.
NEIL is reviewing claims made under the insurance policies to ensure that claims associated with the outage are covered by the policies. The review by NEIL includes the timing of the unit’s return to service and whether the return should have occurred earlier reducing the amount received under the accidental outage policy. Intervenors in the Indiana fuel clause proceeding recommend the remaining accidental outage policy revenues should be given to customers through the fuel clause. The treatment of property damage costs, replacement power costs and insurance proceeds will be the subject of future regulatory proceedings in Indiana and Michigan. If the ultimate costs of the incident are not covered by warranty, insurance or through the regulatory process or if any future regulatory proc eedingsproceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition.
OPERATIONAL CONTINGENCIES
Fort Wayne Lease – Affecting I&M
Since 1975 I&M has leased certain energy delivery assets from the City of Fort Wayne, Indiana under a long-term lease that expired on February 28, 2010. I&M negotiated with Fort Wayne to purchase the assets at the end of the lease, but no agreement was reached prior to the end of the lease. Fort Wayne issued a technical notice of default under the lease to I&M in August 2009. I&M responded to Fort Wayne in October 2009 that it did not agree there was a default under the lease. In October 2009, I&M filed for declaratory and injunctive relief in Indiana state court. The parties agreed to submit this matter to mediation. In February 2010, the court issued a stay to continue mediation. I&M is expensing monthly payments made into an escrow account in lieu of rent.
I&M and Fort Wayne reached a tentative agreement as a result of the mediation process.settlement agreement. The agreement, was signed onin October 28, 2010, and is subject to approval by the Fort Wayne Common Council and the IURC. I&M andfiled a petition with the IURC seeking approval of the agreement, including recovery in rates of payments made to Fort Wayne have agreed to cooperate in promptly seeking the requisite approvals.Wayne. If the agreement is approved, I&M will purchase the remaining leased property and settle claims Fort Wayne asserted. The agreement provides that I&M will pay Fort Wayne a total of $39 million, inclusive of interest, over 15 years and Fort Wayne will recognize that I&M is the exclusive electricity supplier in the Fort Wayne area. I&M will seek recovery in ratesIn April 2011, the Indiana Office of Consumer Utility Counselor filed comments opposing portions of the payments made to Fort Wayne.settlement agreement. The IURC scheduled a hearing for June 2011. If the agreement is not approved by the Fort Wayne Common Council and the IURC, the parties have the right to terminate the agreement and pursue other relief.
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 inv oicedinvoiced at the 1992 Rate and contended that the 1992 Rate was the new rate floor. 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. In August 2009, the U.S. District Court upheld the arbitrati onarbitration board’s decision. BNSF appealed the U.S. District Court’s decision. In September 2010, oral arguments were heard by a panel fordecision to the U.S. Court of Appeals. In December 2010, the Tenth Circuit Court of Appeals affirmed the U.S. District Court’s order confirming the arbitration award, denying BNSF’s underpayments claim. In January 2011, the appellate court issued a mandate to send the case back to the U.S. District Court to address the remaining attorney fee issues to determine the award amount to PSO for attorney’s fees and expenses related to the proceedings at both the district court and appellate court levels.
5.4. ACQUISITION
2011
None
2010
Valley Electric Membership Corporation – Affecting SWEPCo
In November 2009,October 2010, SWEPCo signed a letter of intent to purchasepurchased certain transmission and distribution assets of Valley Electric Membership Corporation (VEMCO). In October 2010, SWEPCo finalized the purchase for approximately $102 million subject to working capital and other adjustments, and began serving VEMCO’s 30,000 customers in Louisiana.
2009
None
6.5. BENEFIT PLANS
APCo, CSPCo, I&M, OPCo, PSO and SWEPCoThe Registrant Subsidiaries participate in an AEP sponsored qualified pension plansplan and two unfunded nonqualified pension plans. A substantial majority ofSubstantially all employees are covered by either onethe qualified plan or both athe qualified and a nonqualified pension plan. In addition, APCo, CSPCo, I&M, OPCo, PSO and SWEPCoThe Registrant Subsidiaries also participate in other postretirement benefitOPEB plans sponsored by AEP to provide medical and deathlife insurance benefits for retired employees.
Components of Net Periodic Benefit Cost
The following tables provide the components of net periodic benefit cost by Registrant Subsidiary for the plans for the three and nine months ended September 30, 2010March 31, 2011 and 2009:2010:
APCo | | | Other Postretirement | | | Other Postretirement | |
| Pension Plans | | Benefit Plans | Pension Plans | | Benefit Plans | |
| Three Months Ended September 30, | | Three Months Ended September 30, | Three Months Ended March 31, | | Three Months Ended March 31, | |
| 2010 | | 2009 | | 2010 | | 2009 | 2011 | | 2010 | | 2011 | | 2010 | |
| (in thousands) | (in thousands) | |
Service Cost | $ | 3,227 | | $ | 3,172 | | $ | 1,431 | | $ | 1,285 | | $ | 1,800 | | | $ | 3,227 | | | $ | 1,246 | | | $ | 1,430 | |
Interest Cost | | 8,489 | | | 8,512 | | | 5,075 | | | 4,928 | | | 8,070 | | | | 8,489 | | | | 4,867 | | | | 5,075 | |
Expected Return on Plan Assets | | (10,952) | | | (11,222) | | | (4,407) | | | (3,383) | | | (10,458 | ) | | | (10,951 | ) | | | (4,496 | ) | | | (4,406 | ) |
Amortization of Transition Obligation | | - | | | - | | | 1,311 | | | 1,311 | | | - | | | | - | | | | 286 | | | | 1,311 | |
Amortization of Prior Service Cost | | 229 | | | 230 | | | - | | | - | |
Amortization of Prior Service Cost (Credit) | | | | 229 | | | | 229 | | | | (43 | ) | | | - | |
Amortization of Net Actuarial Loss | | 2,961 | | | 1,922 | | | 1,352 | | | 1,917 | | | 4,141 | | | | 2,960 | | | | 1,455 | | | | 1,352 | |
Net Periodic Benefit Cost | $ | 3,954 | | $ | 2,614 | | $ | 4,762 | | $ | 6,058 | | $ | 3,782 | | | $ | 3,954 | | | $ | 3,315 | | | $ | 4,762 | |
| | | Other Postretirement |
| Pension Plans | | Benefit Plans |
| Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2010 | | 2009 | | 2010 | | 2009 |
| (in thousands) |
Service Cost | $ | 9,681 | | $ | 9,517 | | $ | 4,291 | | $ | 3,857 |
Interest Cost | | 25,467 | | | 25,537 | | | 15,225 | | | 14,783 |
Expected Return on Plan Assets | | (32,854) | | | (33,664) | | | (13,220) | | | (10,149) |
Amortization of Transition Obligation | | - | | | - | | | 3,933 | | | 3,933 |
Amortization of Prior Service Cost | | 687 | | | 688 | | | - | | | - |
Amortization of Net Actuarial Loss | | 8,882 | | | 5,766 | | | 4,057 | | | 5,749 |
Net Periodic Benefit Cost | $ | 11,863 | | $ | 7,844 | | $ | 14,286 | | $ | 18,173 |
CSPCo | | | Other Postretirement |
| Pension Plans | | Benefit Plans |
| Three Months Ended September 30, | | Three Months Ended September 30, |
| 2010 | | 2009 | | 2010 | | 2009 |
| (in thousands) |
Service Cost | $ | 1,469 | | $ | 1,376 | | $ | 690 | | $ | 618 |
Interest Cost | | 4,789 | | | 4,882 | | | 2,178 | | | 2,124 |
Expected Return on Plan Assets | | (6,589) | | | (6,820) | | | (1,979) | | | (1,532) |
Amortization of Transition Obligation | | - | | | - | | | 608 | | | 607 |
Amortization of Prior Service Cost | | 141 | | | 141 | | | - | | | - |
Amortization of Net Actuarial Loss | | 1,677 | | | 1,108 | | | 565 | | | 821 |
Net Periodic Benefit Cost | $ | 1,487 | | $ | 687 | | $ | 2,062 | | $ | 2,638 |
| | | Other Postretirement | |
CSPCo | | | | 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, | |
| 2010 | | 2009 | | 2010 | | 2009 | 2011 | | 2010 | | 2011 | | 2010 | |
| (in thousands) | (in thousands) | |
Service Cost | $ | 4,405 | | $ | 4,128 | | $ | 2,070 | | $ | 1,853 | | $ | 849 | | | $ | 1,468 | | | $ | 609 | | | $ | 690 | |
Interest Cost | | 14,367 | | | 14,647 | | | 6,535 | | | 6,370 | | | 4,302 | | | | 4,789 | | | | 2,040 | | | | 2,178 | |
Expected Return on Plan Assets | | (19,767) | | | (20,458) | | | (5,937) | | | (4,595) | | | (5,724 | ) | | | (6,589 | ) | | | (1,987 | ) | | | (1,979 | ) |
Amortization of Transition Obligation | | - | | | - | | | 1,824 | | | 1,823 | | | - | | | | - | | | | 11 | | | | 608 | |
Amortization of Prior Service Cost | | 423 | | | 423 | | | - | | | - | |
Amortization of Prior Service Cost (Credit) | | | | 141 | | | | 141 | | | | (18 | ) | | | - | |
Amortization of Net Actuarial Loss | | 5,031 | | | 3,323 | | | 1,695 | | | 2,464 | | | 2,210 | | | | 1,677 | | | | 577 | | | | 565 | |
Net Periodic Benefit Cost | $ | 4,459 | | $ | 2,063 | | $ | 6,187 | | $ | 7,915 | | $ | 1,778 | | | $ | 1,486 | | | $ | 1,232 | | | $ | 2,062 | |
I&M | | | Other Postretirement | | | Other Postretirement | |
| Pension Plans | | Benefit Plans | Pension Plans | | Benefit Plans | |
| Three Months Ended September 30, | | Three Months Ended September 30, | Three Months Ended March 31, | | Three Months Ended March 31, | |
| 2010 | | 2009 | | 2010 | | 2009 | 2011 | | 2010 | | 2011 | | 2010 | |
| (in thousands) | (in thousands) | |
Service Cost | $ | 3,821 | | $ | 3,501 | | $ | 1,688 | | $ | 1,498 | | $ | 2,358 | | | $ | 3,821 | | | $ | 1,530 | | | $ | 1,687 | |
Interest Cost | | 7,271 | | | 7,130 | | | 3,541 | | | 3,419 | | | 6,929 | | | | 7,272 | | | | 3,403 | | | | 3,541 | |
Expected Return on Plan Assets | | (8,759) | | | (8,934) | | | (3,350) | | | (2,565) | | | (9,214 | ) | | | (8,760 | ) | | | (3,472 | ) | | | (3,349 | ) |
Amortization of Transition Obligation | | - | | | - | | | 704 | | | 703 | | | - | | | | - | | | | 47 | | | | 703 | |
Amortization of Prior Service Cost | | 186 | | | 186 | | | - | | | - | |
Amortization of Prior Service Cost (Credit) | | | | 186 | | | | 186 | | | | (59 | ) | | | - | |
Amortization of Net Actuarial Loss | | 2,516 | | | 1,601 | | | 881 | | | 1,304 | | | 3,534 | | | | 2,516 | | | | 891 | | | | 882 | |
Net Periodic Benefit Cost | $ | 5,035 | | $ | 3,484 | | $ | 3,464 | | $ | 4,359 | | $ | 3,793 | | | $ | 5,035 | | | $ | 2,340 | | | $ | 3,464 | |
| | | Other Postretirement | |
OPCo | | | | 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, | |
| 2010 | | 2009 | | 2010 | | 2009 | 2011 | | 2010 | | 2011 | | 2010 | |
| (in thousands) | (in thousands) | |
Service Cost | $ | 11,463 | | $ | 10,502 | | $ | 5,063 | | $ | 4,493 | | $ | 1,708 | | | $ | 2,846 | | | $ | 1,348 | | | $ | 1,356 | |
Interest Cost | | 21,814 | | | 21,390 | | | 10,623 | | | 10,256 | | | 7,776 | | | | 8,186 | | | | 4,335 | | | | 4,447 | |
Expected Return on Plan Assets | | (26,279) | | | (26,800) | | | (10,048) | | | (7,694) | | | (10,642 | ) | | | (10,680 | ) | | | (4,142 | ) | | | (4,045 | ) |
Amortization of Transition Obligation | | - | | | - | | | 2,111 | | | 2,110 | | | - | | | | - | | | | 26 | | | | 1,053 | |
Amortization of Prior Service Cost | | 558 | | | 558 | | | - | | | - | |
Amortization of Prior Service Cost (Credit) | | | | 227 | | | | 227 | | | | (35 | ) | | | - | |
Amortization of Net Actuarial Loss | | 7,548 | | | 4,804 | | | 2,644 | | | 3,910 | | | 3,990 | | | | 2,860 | | | | 1,227 | | | | 1,154 | |
Net Periodic Benefit Cost | $ | 15,104 | | $ | 10,454 | | $ | 10,393 | | $ | 13,075 | | $ | 3,059 | | | $ | 3,439 | | | $ | 2,759 | | | $ | 3,965 | |
OPCo | | | Other Postretirement | |
PSO | | | | Other Postretirement | |
| Pension Plans | | Benefit Plans | Pension Plans | | Benefit Plans | |
| Three Months Ended September 30, | | Three Months Ended September 30, | Three Months Ended March 31, | | Three Months Ended March 31, | |
| 2010 | | 2009 | | 2010 | | 2009 | 2011 | | 2010 | | 2011 | | 2010 | |
| (in thousands) | (in thousands) | |
Service Cost | $ | 2,845 | | $ | 2,759 | | $ | 1,356 | | $ | 1,219 | | $ | 1,438 | | | $ | 1,513 | | | $ | 655 | | | $ | 703 | |
Interest Cost | | 8,186 | | | 8,275 | | | 4,446 | | | 4,331 | | | 3,305 | | | | 3,722 | | | | 1,512 | | | | 1,590 | |
Expected Return on Plan Assets | | (10,680) | | | (11,070) | | | (4,043) | | | (3,140) | | | (4,366 | ) | | | (4,935 | ) | | | (1,566 | ) | | | (1,527 | ) |
Amortization of Transition Obligation | | - | | | - | | | 1,052 | | | 1,053 | | | - | | | | - | | | | - | | | | 702 | |
Amortization of Prior Service Cost | | 227 | | | 228 | | | - | | | - | |
Amortization of Prior Service Credit | | | | (236 | ) | | | (237 | ) | | | (19 | ) | | | - | |
Amortization of Net Actuarial Loss | | 2,861 | | | 1,875 | | | 1,154 | | | 1,676 | | | 1,678 | | | | 1,297 | | | | 388 | | | | 393 | |
Net Periodic Benefit Cost | $ | 3,439 | | $ | 2,067 | | $ | 3,965 | | $ | 5,139 | | $ | 1,819 | | | $ | 1,360 | | | $ | 970 | | | $ | 1,861 | |
| | | Other Postretirement |
| Pension Plans | | Benefit Plans |
| Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2010 | | 2009 | | 2010 | | 2009 |
| (in thousands) |
Service Cost | $ | 8,536 | | $ | 8,276 | | $ | 4,069 | | $ | 3,658 |
Interest Cost | | 24,558 | | | 24,825 | | | 13,339 | | | 12,994 |
Expected Return on Plan Assets | | (32,040) | | | (33,208) | | | (12,132) | | | (9,420) |
Amortization of Transition Obligation | | - | | | - | | | 3,158 | | | 3,158 |
Amortization of Prior Service Cost | | 681 | | | 683 | | | - | | | - |
Amortization of Net Actuarial Loss | | 8,582 | | | 5,625 | | | 3,462 | | | 5,028 |
Net Periodic Benefit Cost | $ | 10,317 | | $ | 6,201 | | $ | 11,896 | | $ | 15,418 |
PSO | | | Other Postretirement |
| Pension Plans | | Benefit Plans |
| Three Months Ended September 30, | | Three Months Ended September 30, |
| 2010 | | 2009 | | 2010 | | 2009 |
| (in thousands) |
Service Cost | $ | 1,513 | | $ | 1,436 | | $ | 704 | | $ | 631 |
Interest Cost | | 3,722 | | | 3,842 | | | 1,590 | | | 1,538 |
Expected Return on Plan Assets | | (4,934) | | | (5,109) | | | (1,528) | | | (1,174) |
Amortization of Transition Obligation | | - | | | - | | | 701 | | | 701 |
Amortization of Prior Service Credit | | (238) | | | (270) | | | - | | | - |
Amortization of Net Actuarial Loss | | 1,297 | | | 871 | | | 394 | | | 587 |
Net Periodic Benefit Cost | $ | 1,360 | | $ | 770 | | $ | 1,861 | | $ | 2,283 |
| | | Other Postretirement |
| Pension Plans | | Benefit Plans |
| Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2010 | | 2009 | | 2010 | | 2009 |
| (in thousands) |
Service Cost | $ | 4,539 | | $ | 4,308 | | $ | 2,111 | | $ | 1,892 |
Interest Cost | | 11,166 | | | 11,526 | | | 4,770 | | | 4,615 |
Expected Return on Plan Assets | | (14,804) | | | (15,328) | | | (4,583) | | | (3,522) |
Amortization of Transition Obligation | | - | | | - | | | 2,104 | | | 2,104 |
Amortization of Prior Service Credit | | (713) | | | (811) | | | - | | | - |
Amortization of Net Actuarial Loss | | 3,891 | | | 2,615 | | | 1,180 | | | 1,761 |
Net Periodic Benefit Cost | $ | 4,079 | | $ | 2,310 | | $ | 5,582 | | $ | 6,850 |
SWEPCo | | | Other Postretirement |
| Pension Plans | | Benefit Plans |
| Three Months Ended September 30, | | Three Months Ended September 30, |
| 2010 | | 2009 | | 2010 | | 2009 |
| (in thousands) |
Service Cost | $ | 1,761 | | $ | 1,689 | | $ | 777 | | $ | 704 |
Interest Cost | | 3,773 | | | 3,889 | | | 1,735 | | | 1,684 |
Expected Return on Plan Assets | | (4,871) | | | (5,020) | | | (1,661) | | | (1,280) |
Amortization of Transition Obligation | | - | | | - | | | 615 | | | 615 |
Amortization of Prior Service Credit | | (199) | | | (229) | | | - | | | - |
Amortization of Net Actuarial Loss | | 1,310 | | | 879 | | | 427 | | | 640 |
Net Periodic Benefit Cost | $ | 1,774 | | $ | 1,208 | | $ | 1,893 | | $ | 2,363 |
| | | Other Postretirement |
| Pension Plans | | Benefit Plans |
| Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2010 | | 2009 | | 2010 | | 2009 |
| (in thousands) |
Service Cost | $ | 5,284 | | $ | 5,067 | | $ | 2,331 | | $ | 2,113 |
Interest Cost | | 11,320 | | | 11,668 | | | 5,205 | | | 5,052 |
Expected Return on Plan Assets | | (14,616) | | | (15,062) | | | (4,984) | | | (3,840) |
Amortization of Transition Obligation | | - | | | - | | | 1,845 | | | 1,845 |
Amortization of Prior Service Credit | | (597) | | | (687) | | | - | | | - |
Amortization of Net Actuarial Loss | | 3,931 | | | 2,637 | | | 1,283 | | | 1,920 |
Net Periodic Benefit Cost | $ | 5,322 | | $ | 3,623 | | $ | 5,680 | | $ | 7,090 |
The following table provides the actual contributions and payments by Registrant Subsidiary for the pension and OPEB plans during the first nine months of 2010 and the expected contributions and payments for the remainder of 2010:
| | Paid as of September 30, | | Remainder Expected to be Paid in 2010 |
| | | | | Other Postretirement | | | | | Other Postretirement |
Company | | Pension Plans | | Benefit Plans | | Pension Plans | | Benefit Plans |
| | (in thousands) |
APCo | | | $ | 31,979 | | | $ | 15,579 | | | $ | 4,627 | | | $ | 3,067 |
CSPCo | | | | 5,361 | | | | 6,683 | | | | 1,565 | | | | 1,787 |
I&M | | | | 66,733 | | | | 11,541 | | | | 4,754 | | | | 3,549 |
OPCo | | | | 47,222 | | | | 13,661 | | | | 4,286 | | | | 3,068 |
PSO | | | | 11,147 | | | | 6,133 | | | | 1,663 | | | | 2,013 |
SWEPCo | | | | 26,739 | | | | 6,267 | | | | 2,294 | | | | 2,049 |
SWEPCo | | | Other Postretirement | |
| Pension Plans | | Benefit Plans | |
| Three Months Ended March 31, | | Three Months Ended March 31, | |
| 2011 | | 2010 | | 2011 | | 2010 | |
| (in thousands) | |
Service Cost | | $ | 1,642 | | | $ | 1,762 | | | $ | 757 | | | $ | 777 | |
Interest Cost | | | 3,318 | | | | 3,774 | | | | 1,742 | | | | 1,735 | |
Expected Return on Plan Assets | | | (4,595 | ) | | | (4,873 | ) | | | (1,800 | ) | | | (1,662 | ) |
Amortization of Transition Obligation | | | - | | | | - | | | | - | | | | 615 | |
Amortization of Prior Service Cost (Credit) | | | (198 | ) | | | (199 | ) | | | 65 | | | | - | |
Amortization of Net Actuarial Loss | | | 1,680 | | | | 1,310 | | | | 446 | | | | 428 | |
Net Periodic Benefit Cost | | $ | 1,847 | | | $ | 1,774 | | | $ | 1,210 | | | $ | 1,893 | |
7.6. BUSINESS SEGMENTS
The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
8.7. DERIVATIVES AND HEDGING
OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS
The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers 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 the Registrant Subsidiaries due to changes in the underlying market prices or rates. TheseAEPSC, on behalf of the Registrant Subsidiaries, manages these risks are managed using derivative instruments.
STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES
Trading Strategies
The strategy surrounding the use of derivative instruments for trading purposes focuses on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries.
Risk Management Strategies
The strategy surrounding the use of derivative instruments focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal 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 the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance.
AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and 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-termthe Registrant Subsidiaries’ commodity derivative positions.portfolio. 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 tables represent the gross notional volume of the Registrant Subsidiaries’ outstanding derivative contracts as of September 30, 2010March 31, 2011 and December 31, 2009:2010:
Notional Volume of Derivative Instruments | September 30, 2010 | |
(in thousands) | |
March 31, 2011 | | March 31, 2011 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Primary Risk | Primary Risk | | Unit of | | | | | | | | | | | | | Primary Risk | | Unit of | | | | | | | | | | | | |
Exposure | Exposure | | Measure | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo | Exposure | | Measure | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | | | (in thousands) |
Commodity: | Commodity: | | | | | | | | | | | | | | | | | | | | | Commodity: | | | | | | | | | | | | | | | | | | | | |
| Power | | MWHs | | | 237,981 | | | 137,187 | | | 144,273 | | | 167,450 | | | 33 | | | 57 | Power | | MWHs | | | 159,506 | | | 91,314 | | | 94,583 | | | 109,542 | | | 22 | | | 26 |
| Coal | | Tons | | | 15,365 | | | 8,163 | | | 6,099 | | | 25,606 | | | 4,490 | | | 8,581 | Coal | | Tons | | | 7,623 | | | 4,688 | | | 7,683 | | | 24,587 | | | 4,523 | | | 7,773 |
| Natural Gas | | MMBtus | | | 5,483 | | | 3,161 | | | 3,297 | | | 3,858 | | | 81 | | | 97 | Natural Gas | | MMBtus | | | 3,141 | | | 1,798 | | | 1,843 | | | 2,156 | | | 24 | | | 29 |
| Heating Oil and | | | | | | | | | | | | | | | | | | | | | Heating Oil and | | | | | | | | | | | | | | | | | | | | |
| | Gasoline | | Gallons | | | 1,361 | | | 598 | | | 671 | | | 1,005 | | | 796 | | | 733 | | Gasoline | | Gallons | | | 1,154 | | | 513 | | | 572 | | | 855 | | | 674 | | | 621 |
| Interest Rate | | USD | | $ | 11,130 | | $ | 6,394 | | $ | 6,592 | | $ | 8,293 | | $ | 652 | | $ | 899 | Interest Rate | | USD | | $ | 43,158 | | $ | 24,712 | | $ | 25,382 | | $ | 29,957 | | $ | 309 | | $ | 410 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Interest Rate and | Interest Rate and | | | | | | | | | | | | | | | | | | | | Interest Rate and | | | | | | | | | | | | | | | | | | | |
| Foreign Currency | | USD | | $ | 200,000 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | 1,319 | Foreign Currency | | USD | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | 195 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Notional Volume of Derivative Instruments | December 31, 2009 | |
(in thousands) | |
December 31, 2010 | | December 31, 2010 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Primary Risk | Primary Risk | | Unit of | | | | | | | | | | | | | Primary Risk | | Unit of | | | | | | | | | | | | |
Exposure | Exposure | | Measure | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo | Exposure | | Measure | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | | | (in thousands) |
Commodity: | Commodity: | | | | | | | | | | | | | | | | | | | | | Commodity: | | | | | | | | | | | | | | | | | | | | |
| Power | | MWHs | | | 191,121 | | | 96,828 | | | 99,265 | | | 112,745 | | | 10 | | | 12 | Power | | MWHs | | | 194,217 | | | 111,959 | | | 117,862 | | | 136,657 | | | 21 | | | 34 |
| Coal | | Tons | | | 11,347 | | | 5,615 | | | 5,150 | | | 23,631 | | | 5,936 | | | 6,790 | Coal | | Tons | | | 11,195 | | | 5,550 | | | 6,571 | | | 23,033 | | | 4,936 | | | 8,777 |
| Natural Gas | | MMBtus | | | 17,867 | | | 9,051 | | | 9,129 | | | 10,539 | | | - | | | - | Natural Gas | | MMBtus | | | 2,166 | | | 1,248 | | | 1,302 | | | 1,524 | | | 15 | | | 19 |
| Heating Oil and | | | | | | | | | | | | | | | | | | | | | Heating Oil and | | | | | | | | | | | | | | | | | | | | |
| | Gasoline | | Gallons | | | 1,164 | | | 474 | | | 552 | | | 838 | | | 668 | | | 628 | | Gasoline | | Gallons | | | 1,054 | | | 467 | | | 521 | | | 776 | | | 616 | | | 564 |
| Interest Rate | | USD | | $ | 21,054 | | $ | 10,658 | | $ | 10,716 | | $ | 13,487 | | $ | 1,137 | | $ | 1,457 | Interest Rate | | USD | | $ | 9,541 | | $ | 5,471 | | $ | 5,732 | | $ | 7,185 | | $ | 609 | | $ | 793 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Interest Rate and | Interest Rate and | | | | | | | | | | | | | | | | | | | | Interest Rate and | | | | | | | | | | | | | | | | | | | |
| Foreign Currency | | USD | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | 3,798 | Foreign Currency | | USD | | $ | 200,000 | | $ | - | | $ | - | | $ | - | | $ | 200,000 | | $ | 189 |
Fair Value Hedging Strategies
AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.
Cash Flow Hedging Strategies
AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. Management 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.
The Registrant Subsidiaries’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. For disclosure purposes, these contracts are included with other hedging activity as “Commodity.” The Registrant Subsidiaries do not hedge all fuel price risk.
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.
At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily becausewhen 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.
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS |
The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on 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 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 curre ntcurrent 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 the accounting guidance for “Derivatives and Hedging,” 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 September 30, 2010March 31, 2011 and December 31, 20092010 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:
| | | September 30, 2010 | | December 31, 2009 | | March 31, 2011 | | December 31, 2010 | |
| | | Cash Collateral | | Cash Collateral | | Cash Collateral | | Cash Collateral | | Cash Collateral | | Cash Collateral | | Cash Collateral | | Cash Collateral | |
| | | Received | | Paid | | Received | | Paid | | Received | | Paid | | Received | | Paid | |
| | | Netted Against | | Netted Against | | Netted Against | | Netted Against | | Netted Against | | Netted Against | | Netted Against | | Netted Against | |
| | | Risk Management | | Risk Management | | Risk Management | | Risk Management | | Risk Management | | Risk Management | | Risk Management | | Risk Management | |
Company | Company | | Assets | | Liabilities | | Assets | | Liabilities | | Assets | | Liabilities | | Assets | | Liabilities | |
| | | (in thousands) | | (in thousands) | |
APCo | APCo | | $ | 6,306 | | $ | 46,860 | | $ | 3,789 | | $ | 31,806 | | | $ | 1,324 | | | $ | 18,013 | | | $ | 1,809 | | | $ | 16,229 | |
CSPCo | CSPCo | | 3,636 | | 27,007 | | 1,920 | | 16,108 | | | | 758 | | | | 10,312 | | | | 1,042 | | | | 9,347 | |
I&M | I&M | | 3,792 | | 28,150 | | 1,936 | | 16,222 | | | | 777 | | | | 10,573 | | | | 1,087 | | | | 9,757 | |
OPCo | OPCo | | 4,438 | | 33,098 | | 2,235 | | 19,512 | | | | 909 | | | | 12,375 | | | | 1,272 | | | | 11,561 | |
PSO | PSO | | - | | 55 | | - | | 194 | | | | 3 | | | | 5 | | | | - | | | | 44 | |
SWEPCo | SWEPCo | | - | | 88 | | - | | 305 | | | | 4 | | | | 7 | | | | - | | | | 72 | |
The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the Condensed Balance Sheets as of September 30, 2010March 31, 2011 and December 31, 2009:2010:
Fair Value of Derivative Instruments | September 30, 2010 | |
March 31, 2011 | | March 31, 2011 |
| | | | | | | | | | | | | | | | | | | | | | |
APCo | APCo | | | | | | | | | | | | APCo | | | | | | | | | | | |
| | | Risk | | | | | | | | | | | Risk | | | | | | | | |
| | | Management | | | | | | | | | | | Management | | | | | | | | |
| | | Contracts | | Hedging Contracts | | | | | | | Contracts | | Hedging Contracts | | | | |
| | | | | | | | Interest Rate | | | | | | | | | | | | Interest Rate | | | | |
| | | Commodity | | Commodity | | and Foreign | | | | | | | | | | | and Foreign | | | | |
Balance Sheet Location | Balance Sheet Location | | (a) | | (a) | | Currency (a) | | Other (a) (b) | | Total | Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Currency (a) | | Other (a) (b) | | Total |
| | | (in thousands) | | | (in thousands) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 358,539 | | $ | 1,548 | | $ | - | | $ | (298,888) | | $ | 61,199 | Current Risk Management Assets | | $ | 210,704 | | $ | 3,016 | | $ | - | | $ | (174,797) | | $ | 38,923 |
Long-term Risk Management Assets | Long-term Risk Management Assets | | | 164,200 | | | 14 | | | - | | | (112,348) | | | 51,866 | Long-term Risk Management Assets | | | 88,548 | | | 699 | | | - | | | (48,981) | | | 40,266 |
Total Assets | Total Assets | | | 522,739 | | | 1,562 | | | - | | | (411,236) | | | 113,065 | Total Assets | | | 299,252 | | | 3,715 | | | - | | | (223,778) | | | 79,189 |
| | | | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | Current Risk Management Liabilities | | 344,792 | | 4,657 | | 1,216 | | (322,472) | | 28,193 | Current Risk Management Liabilities | | 206,660 | | 2,709 | | - | | (186,623) | | 22,746 |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | | 149,635 | | | 202 | | | - | | | (133,508) | | | 16,329 | Long-term Risk Management Liabilities | | | 69,582 | | | 756 | | | - | | | (56,999) | | | 13,339 |
Total Liabilities | Total Liabilities | | | 494,427 | | | 4,859 | | | 1,216 | | | (455,980) | | | 44,522 | Total Liabilities | | | 276,242 | | | 3,465 | | | - | | | (243,622) | | | 36,085 |
| | | | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net | Total MTM Derivative Contract Net | | | | | | | | | | | | Total MTM Derivative Contract Net | | | | | | | | | | | |
| Assets (Liabilities) | | $ | 28,312 | | $ | (3,297) | | $ | (1,216) | | $ | 44,744 | | $ | 68,543 | Assets (Liabilities) | | $ | 23,010 | | $ | 250 | | $ | - | | $ | 19,844 | | $ | 43,104 |
| | | | | | | | | | | | | | | | | | | | | | |
Fair Value of Derivative Instruments | December 31, 2009 | |
December 31, 2010 | | December 31, 2010 |
| | | | | | | | | | | | | | | | | | | | | | |
APCo | APCo | | | | | | | | | | | | APCo | | | | | | | | | | | |
| | | Risk | | | | | | | | | | | Risk | | | | | | | | |
| | | Management | | | | | | | | | | | Management | | | | | | | | |
| | | Contracts | | Hedging Contracts | | | | | | | Contracts | | Hedging Contracts | | | | |
| | | | | | | | Interest Rate | | | | | | | | | | | | Interest Rate | | | | |
| | | Commodity | | Commodity | | and Foreign | | | | | | | | | | | and Foreign | | | | |
Balance Sheet Location | Balance Sheet Location | | (a) | | (a) | | Currency (a) | | Other (a) (b) | | Total | Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Currency (a) | | Other (a) (b) | | Total |
| | | (in thousands) | | | (in thousands) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 332,764 | | $ | 3,621 | | $ | - | | $ | (268,429) | | $ | 67,956 | Current Risk Management Assets | | $ | 267,702 | | $ | 1,956 | | $ | 11,888 | | $ | (228,304) | | $ | 53,242 |
Long-term Risk Management Assets | Long-term Risk Management Assets | | | 132,044 | | | - | | | - | | | (84,903) | | | 47,141 | Long-term Risk Management Assets | | | 79,560 | | | 714 | | | - | | | (41,854) | | | 38,420 |
Total Assets | Total Assets | | | 464,808 | | | 3,621 | | | - | | | (353,332) | | | 115,097 | Total Assets | | | 347,262 | | | 2,670 | | | 11,888 | | | (270,158) | | | 91,662 |
| | | | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | Current Risk Management Liabilities | | 309,639 | | 5,084 | | - | | (288,931) | | 25,792 | Current Risk Management Liabilities | | 262,027 | | 2,363 | | - | | (236,397) | | 27,993 |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | | 118,702 | | | 80 | | | - | | | (98,418) | | | 20,364 | Long-term Risk Management Liabilities | | | 61,724 | | | 701 | | | - | | | (51,552) | | | 10,873 |
Total Liabilities | Total Liabilities | | | 428,341 | | | 5,164 | | | - | | | (387,349) | | | 46,156 | Total Liabilities | | | 323,751 | | | 3,064 | | | - | | | (287,949) | | | 38,866 |
| | | | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net | Total MTM Derivative Contract Net | | | | | | | | | | | | Total MTM Derivative Contract Net | | | | | | | | | | | |
| Assets (Liabilities) | | $ | 36,467 | | $ | (1,543) | | $ | - | | $ | 34,017 | | $ | 68,941 | Assets (Liabilities) | | $ | 23,511 | | $ | (394) | | $ | 11,888 | | $ | 17,791 | | $ | 52,796 |
Fair Value of Derivative Instruments | September 30, 2010 | |
March 31, 2011 | | March 31, 2011 |
| | | | | | | | | | | | | | | | | | | | | | |
CSPCo | CSPCo | | | | | | | | | | | | CSPCo | | | | | | | | | | | |
| | | Risk | | | | | | | | | | | Risk | | | | | | | | |
| | | Management | | | | | | | | | | | Management | | | | | | | | |
| | | Contracts | | Hedging Contracts | | | | | | | Contracts | | Hedging Contracts | | | | |
| | | | | | | | Interest Rate | | | | | | | | | | | | Interest Rate | | | | |
| | | Commodity | | Commodity | | and Foreign | | | | | | | | | | | and Foreign | | | | |
Balance Sheet Location | Balance Sheet Location | | (a) | | (a) | | Currency (a) | | Other (a) (b) | | Total | Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Currency (a) | | Other (a) (b) | | Total |
| | | (in thousands) | | | (in thousands) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 205,558 | | $ | 878 | | $ | - | | $ | (171,270) | | $ | 35,166 | Current Risk Management Assets | | $ | 121,773 | | $ | 1,647 | | $ | - | | $ | (101,199) | | $ | 22,221 |
Long-term Risk Management Assets | Long-term Risk Management Assets | | | 94,390 | | | 6 | | | - | | | (64,514) | | | 29,882 | Long-term Risk Management Assets | | | 50,892 | | | 400 | | | - | | | (28,212) | | | 23,080 |
Total Assets | Total Assets | | | 299,948 | | | 884 | | | - | | | (235,784) | | | 65,048 | Total Assets | | | 172,665 | | | 2,047 | | | - | | | (129,411) | | | 45,301 |
| | | | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | Current Risk Management Liabilities | | 197,685 | | 2,676 | | - | | (184,861) | | 15,500 | Current Risk Management Liabilities | | 119,471 | | 1,551 | | - | | (107,969) | | 13,053 |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | | 85,983 | | | 116 | | | - | | | (76,710) | | | 9,389 | Long-term Risk Management Liabilities | | | 40,022 | | | 433 | | | - | | | (32,802) | | | 7,653 |
Total Liabilities | Total Liabilities | | | 283,668 | | | 2,792 | | | - | | | (261,571) | | | 24,889 | Total Liabilities | | | 159,493 | | | 1,984 | | | - | | | (140,771) | | | 20,706 |
| | | | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net | Total MTM Derivative Contract Net | | | | | | | | | | | | Total MTM Derivative Contract Net | | | | | | | | | | | |
| Assets (Liabilities) | | $ | 16,280 | | $ | (1,908) | | $ | - | | $ | 25,787 | | $ | 40,159 | Assets (Liabilities) | | $ | 13,172 | | $ | 63 | | $ | - | | $ | 11,360 | | $ | 24,595 |
| | | | | | | | | | | | | | | | | | | | | | | | |
Fair Value of Derivative Instruments | December 31, 2009 | |
December 31, 2010 | | December 31, 2010 |
| | | | | | | | | | | | | | | | | | | | | | | | |
CSPCo | CSPCo | | | | | | | | | | | | CSPCo | | | | | | | | | | | |
| | | Risk | | | | | | | | | | | Risk | | | | | | | | |
| | | Management | | | | | | | | | | | Management | | | | | | | | |
| | | Contracts | | Hedging Contracts | | | | | | | Contracts | | Hedging Contracts | | | | |
| | | | | | | | Interest Rate | | | | | | | | | | | | Interest Rate | | | | |
| | | Commodity | | Commodity | | and Foreign | | | | | | | | | | | and Foreign | | | | |
Balance Sheet Location | Balance Sheet Location | | (a) | | (a) | | Currency (a) | | Other (a) (b) | | Total | Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Currency (a) | | Other (a) (b) | | Total |
| | | (in thousands) | | | (in thousands) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 168,137 | | $ | 1,805 | | $ | - | | $ | (135,599) | | $ | 34,343 | Current Risk Management Assets | | $ | 149,886 | | $ | 1,164 | | $ | - | | $ | (127,276) | | $ | 23,774 |
Long-term Risk Management Assets | Long-term Risk Management Assets | | | 66,816 | | | - | | | - | | | (42,934) | | | 23,882 | Long-term Risk Management Assets | | | 45,413 | | | 412 | | | - | | | (23,736) | | | 22,089 |
Total Assets | Total Assets | | | 234,953 | | | 1,805 | | | - | | | (178,533) | | | 58,225 | Total Assets | | | 195,299 | | | 1,576 | | | - | | | (151,012) | | | 45,863 |
| | | | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | Current Risk Management Liabilities | | 156,463 | | 2,574 | | - | | (145,985) | | 13,052 | Current Risk Management Liabilities | | 146,540 | | 1,362 | | - | | (131,935) | | 15,967 |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | | 60,048 | | | 41 | | | - | | | (49,776) | | | 10,313 | Long-term Risk Management Liabilities | | | 35,144 | | | 404 | | | - | | | (29,325) | | | 6,223 |
Total Liabilities | Total Liabilities | | | 216,511 | | | 2,615 | | | - | | | (195,761) | | | 23,365 | Total Liabilities | | | 181,684 | | | 1,766 | | | - | | | (161,260) | | | 22,190 |
| | | | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net | Total MTM Derivative Contract Net | | | | | | | | | | | | Total MTM Derivative Contract Net | | | | | | | | | | | |
| Assets (Liabilities) | | $ | 18,442 | | $ | (810) | | $ | - | | $ | 17,228 | | $ | 34,860 | Assets (Liabilities) | | $ | 13,615 | | $ | (190) | | $ | - | | $ | 10,248 | | $ | 23,673 |
Fair Value of Derivative Instruments | September 30, 2010 | |
March 31, 2011 | | March 31, 2011 |
| | | | | | | | | | | | | | | | | | | | | | |
I&M | I&M | | | | | | | | | | | | I&M | | | | | | | | | | | |
| | | Risk | | | | | | | | | | | Risk | | | | | | | | |
| | | Management | | | | | | | | | | | Management | | | | | | | | |
| | | Contracts | | Hedging Contracts | | | | | | | Contracts | | Hedging Contracts | | | | |
| | | | | | | | Interest Rate | | | | | | | | | | | | Interest Rate | | | | |
| | | Commodity | | Commodity | | and Foreign | | | | | | | | | | | and Foreign | | | | |
Balance Sheet Location | Balance Sheet Location | | (a) | | (a) | | Currency (a) | | Other (a) (b) | | Total | Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Currency (a) | | Other (a) (b) | | Total |
| | | (in thousands) | | | (in thousands) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 213,839 | | $ | 921 | | $ | - | | $ | (175,043) | | $ | 39,717 | Current Risk Management Assets | | $ | 138,531 | | $ | 1,713 | | $ | - | | $ | (113,808) | | $ | 26,436 |
Long-term Risk Management Assets | Long-term Risk Management Assets | | | 107,923 | | | 7 | | | - | | | (66,430) | | | 41,500 | Long-term Risk Management Assets | | | 61,967 | | | 410 | | | - | | | (30,454) | | | 31,923 |
Total Assets | Total Assets | | | 321,762 | | | 928 | | | - | | | (241,473) | | | 81,217 | Total Assets | | | 200,498 | | | 2,123 | | | - | | | (144,262) | | | 58,359 |
| | | | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | Current Risk Management Liabilities | | 202,473 | | 2,793 | | - | | (189,211) | | 16,055 | Current Risk Management Liabilities | | 132,824 | | 1,590 | | - | | (120,751) | | 13,663 |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | | 88,732 | | | 121 | | | - | | | (79,140) | | | 9,713 | Long-term Risk Management Liabilities | | | 42,708 | | | 443 | | | - | | | (35,159) | | | 7,992 |
Total Liabilities | Total Liabilities | | | 291,205 | | | 2,914 | | | - | | | (268,351) | | | 25,768 | Total Liabilities | | | 175,532 | | | 2,033 | | | - | | | (155,910) | | | 21,655 |
| | | | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net | Total MTM Derivative Contract Net | | | | | | | | | | | | Total MTM Derivative Contract Net | | | | | | | | | | | |
| Assets (Liabilities) | | $ | 30,557 | | $ | (1,986) | | $ | - | | $ | 26,878 | | $ | 55,449 | Assets (Liabilities) | | $ | 24,966 | | $ | 90 | | $ | - | | $ | 11,648 | | $ | 36,704 |
| | | | | | | | | | | | | | | | | | | | | | |
Fair Value of Derivative Instruments | December 31, 2009 | |
December 31, 2010 | | December 31, 2010 |
| | | | | | | | | | | | | | | | | | | | | | |
I&M | I&M | | | | | | | | | | | | I&M | | | | | | | | | | | |
| | | Risk | | | | | | | | | | | Risk | | | | | | | | |
| | | Management | | | | | | | | | | | Management | | | | | | | | |
| | | Contracts | | Hedging Contracts | | | | | | | Contracts | | Hedging Contracts | | | | |
| | | | | | | | Interest Rate | | | | | | | | | | | | Interest Rate | | | | |
| | | Commodity | | Commodity | | and Foreign | | | | | | | | | | | and Foreign | | | | |
Balance Sheet Location | Balance Sheet Location | | (a) | | (a) | | Currency (a) | | Other (a) (b) | | Total | Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Currency (a) | | Other (a) (b) | | Total |
| | | (in thousands) | | | (in thousands) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 167,847 | | $ | 1,839 | | $ | - | | $ | (135,248) | | $ | 34,438 | Current Risk Management Assets | | $ | 162,896 | | $ | 1,151 | | $ | - | | $ | (136,521) | | $ | 27,526 |
Long-term Risk Management Assets | Long-term Risk Management Assets | | | 72,127 | | | - | | | - | | | (42,993) | | | 29,134 | Long-term Risk Management Assets | | | 56,154 | | | 429 | | | - | | | (25,098) | | | 31,485 |
Total Assets | Total Assets | | | 239,974 | | | 1,839 | | | - | | | (178,241) | | | 63,572 | Total Assets | | | 219,050 | | | 1,580 | | | - | | | (161,619) | | | 59,011 |
| | | | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | Current Risk Management Liabilities | | 156,561 | | 2,596 | | - | | (145,721) | | 13,436 | Current Risk Management Liabilities | | 156,750 | | 1,421 | | - | | (141,386) | | 16,785 |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | | 60,217 | | | 41 | | | - | | | (49,872) | | | 10,386 | Long-term Risk Management Liabilities | | | 37,039 | | | 421 | | | - | | | (30,930) | | | 6,530 |
Total Liabilities | Total Liabilities | | | 216,778 | | | 2,637 | | | - | | | (195,593) | | | 23,822 | Total Liabilities | | | 193,789 | | | 1,842 | | | - | | | (172,316) | | | 23,315 |
| | | | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net | Total MTM Derivative Contract Net | | | | | | | | | | | | Total MTM Derivative Contract Net | | | | | | | | | | | |
| Assets (Liabilities) | | $ | 23,196 | | $ | (798) | | $ | - | | $ | 17,352 | | $ | 39,750 | Assets (Liabilities) | | $ | 25,261 | | $ | (262) | | $ | - | | $ | 10,697 | | $ | 35,696 |
Fair Value of Derivative Instruments | September 30, 2010 | |
March 31, 2011 | | March 31, 2011 |
| | | | | | | | | | | | | | | | | | | | | | |
OPCo | OPCo | | | | | | | | | | | | OPCo | | | | | | | | | | | |
| | | Risk | | | | | | | | | | | Risk | | | | | | | | |
| | | Management | | | | | | | | | | | Management | | | | | | | | |
| | | Contracts | | Hedging Contracts | | | | | | | Contracts | | Hedging Contracts | | | | |
| | | | | | | | Interest Rate | | | | | | | | | | | | Interest Rate | | | | |
| | | Commodity | | Commodity | | and Foreign | | | | | | | | | | | and Foreign | | | | |
Balance Sheet Location | Balance Sheet Location | | (a) | | (a) | | Currency (a) | | Other (a) (b) | | Total | Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Currency (a) | | Other (a) (b) | | Total |
| | | (in thousands) | | | (in thousands) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 275,750 | | $ | 1,092 | | $ | - | | $ | (231,993) | | $ | 44,849 | Current Risk Management Assets | | $ | 213,460 | | $ | 2,108 | | $ | - | | $ | (187,792) | | $ | 27,776 |
Long-term Risk Management Assets | Long-term Risk Management Assets | | | 121,042 | | | 9 | | | - | | | (84,228) | | | 36,823 | Long-term Risk Management Assets | | | 72,831 | | | 480 | | | - | | | (43,927) | | | 29,384 |
Total Assets | Total Assets | | | 396,792 | | | 1,101 | | | - | | | (316,221) | | | 81,672 | Total Assets | | | 286,291 | | | 2,588 | | | - | | | (231,719) | | | 57,160 |
| | | | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | Current Risk Management Liabilities | | 267,657 | | 3,278 | | - | | (248,642) | | 22,293 | Current Risk Management Liabilities | | 211,485 | | 1,861 | | - | | (195,915) | | 17,431 |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | | 111,022 | | | 143 | | | - | | | (99,187) | | | 11,978 | Long-term Risk Management Liabilities | | | 59,066 | | | 519 | | | - | | | (49,436) | | | 10,149 |
Total Liabilities | Total Liabilities | | | 378,679 | | | 3,421 | | | - | | | (347,829) | | | 34,271 | Total Liabilities | | | 270,551 | | | 2,380 | | | - | | | (245,351) | | | 27,580 |
| | | | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net | Total MTM Derivative Contract Net | | | | | | | | | | | | Total MTM Derivative Contract Net | | | | | | | | | | | |
| Assets (Liabilities) | | $ | 18,113 | | $ | (2,320) | | $ | - | | $ | 31,608 | | $ | 47,401 | Assets (Liabilities) | | $ | 15,740 | | $ | 208 | | $ | - | | $ | 13,632 | | $ | 29,580 |
| | | | | | | | | | | | | | | | | | | | | | |
Fair Value of Derivative Instruments | December 31, 2009 | |
December 31, 2010 | | December 31, 2010 |
| | | | | | | | | | | | | | | | | | | | | | |
OPCo | OPCo | | | | | | | | | | | | OPCo | | | | | | | | | | | |
| | | Risk | | | | | | | | | | | Risk | | | | | | | | |
| | | Management | | | | | | | | | | | Management | | | | | | | | |
| | | Contracts | | Hedging Contracts | | | | | | | Contracts | | Hedging Contracts | | | | |
| | | | | | | | Interest Rate | | | | | | | | | | | | Interest Rate | | | | |
| | | Commodity | | Commodity | | and Foreign | | | | | | | | | | | and Foreign | | | | |
Balance Sheet Location | Balance Sheet Location | | (a) | | (a) | | Currency (a) | | Other (a) (b) | | Total | Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Currency (a) | | Other (a) (b) | | Total |
| | | (in thousands) | | | (in thousands) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 255,179 | | $ | 2,199 | | $ | - | | $ | (207,330) | | $ | 50,048 | Current Risk Management Assets | | $ | 262,751 | | $ | 1,316 | | $ | - | | $ | (233,294) | | $ | 30,773 |
Long-term Risk Management Assets | Long-term Risk Management Assets | | | 88,064 | | | - | | | - | | | (60,061) | | | 28,003 | Long-term Risk Management Assets | | | 63,533 | | | 503 | | | - | | | (36,024) | | | 28,012 |
Total Assets | Total Assets | | | 343,243 | | | 2,199 | | | - | | | (267,391) | | | 78,051 | Total Assets | | | 326,284 | | | 1,819 | | | - | | | (269,318) | | | 58,785 |
| | | | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | Current Risk Management Liabilities | | 240,877 | | 2,998 | | - | | (219,484) | | 24,391 | Current Risk Management Liabilities | | 259,635 | | 1,663 | | - | | (239,132) | | 22,166 |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | | 81,186 | | | 47 | | | - | | | (68,723) | | | 12,510 | Long-term Risk Management Liabilities | | | 50,757 | | | 493 | | | - | | | (42,847) | | | 8,403 |
Total Liabilities | Total Liabilities | | | 322,063 | | | 3,045 | | | - | | | (288,207) | | | 36,901 | Total Liabilities | | | 310,392 | | | 2,156 | | | - | | | (281,979) | | | 30,569 |
| | | | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net | Total MTM Derivative Contract Net | | | | | | | | | | | | Total MTM Derivative Contract Net | | | | | | | | | | | |
| Assets (Liabilities) | | $ | 21,180 | | $ | (846) | | $ | - | | $ | 20,816 | | $ | 41,150 | Assets (Liabilities) | | $ | 15,892 | | $ | (337) | | $ | - | | $ | 12,661 | | $ | 28,216 |
Fair Value of Derivative Instruments | September 30, 2010 | |
March 31, 2011 | | March 31, 2011 |
| | | | | | | | | | | | | | | | | | | | | | |
PSO | PSO | | | | | | | | | | | | PSO | | | | | | | | | | | |
| | | Risk | | | | | | | | | | | Risk | | | | | | | | |
| | | Management | | | | | | | | | | | Management | | | | | | | | |
| | | Contracts | | Hedging Contracts | | | | | | | Contracts | | Hedging Contracts | | | | |
| | | | | | | | Interest Rate | | | | | | | | | | | | Interest Rate | | | | |
| | | Commodity | | Commodity | | and Foreign | | | | | | | | | | | and Foreign | | | | |
Balance Sheet Location | Balance Sheet Location | | (a) | | (a) | | Currency (a) | | Other (a) (b) | | Total | Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Currency (a) | | Other (a) (b) | | Total |
| | | (in thousands) | | | (in thousands) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 7,587 | | $ | 65 | | $ | - | | $ | (4,652) | | $ | 3,000 | Current Risk Management Assets | | $ | 13,454 | | $ | 376 | | $ | - | | $ | (13,150) | | $ | 680 |
Long-term Risk Management Assets | Long-term Risk Management Assets | | | 1,604 | | | 4 | | | - | | | (1,107) | | | 501 | Long-term Risk Management Assets | | | 2,344 | | | - | | | - | | | (1,993) | | | 351 |
Total Assets | Total Assets | | | 9,191 | | | 69 | | | - | | | (5,759) | | | 3,501 | Total Assets | | | 15,798 | | | 376 | | | - | | | (15,143) | | | 1,031 |
| | | | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | Current Risk Management Liabilities | | 4,928 | | 63 | | - | | (4,683) | | 308 | Current Risk Management Liabilities | | 14,331 | | - | | - | | (13,138) | | 1,193 |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | | 1,228 | | | 6 | | | - | | | (1,115) | | | 119 | Long-term Risk Management Liabilities | | | 2,200 | | | - | | | - | | | (2,007) | | | 193 |
Total Liabilities | Total Liabilities | | | 6,156 | | | 69 | | | - | | | (5,798) | | | 427 | Total Liabilities | | | 16,531 | | | - | | | - | | | (15,145) | | | 1,386 |
| | | | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net | Total MTM Derivative Contract Net | | | | | | | | | | | | Total MTM Derivative Contract Net | | | | | | | | | | | |
| Assets (Liabilities) | | $ | 3,035 | | $ | - | | $ | - | | $ | 39 | | $ | 3,074 | Assets (Liabilities) | | $ | (733) | | $ | 376 | | $ | - | | $ | 2 | | $ | (355) |
| | | | | | | | | | | | | | | | | | | | | | |
Fair Value of Derivative Instruments | December 31, 2009 | |
December 31, 2010 | | December 31, 2010 |
| | | | | | | | | | | | | | | | | | | | | | |
PSO | PSO | | | | | | | | | | | | PSO | | | | | | | | | | | |
| | | Risk | | | | | | | | | | | Risk | | | | | | | | |
| | | Management | | | | | | | | | | | Management | | | | | | | | |
| | | Contracts | | Hedging Contracts | | | | | | | Contracts | | Hedging Contracts | | | | |
| | | | | | | | Interest Rate | | | | | | | | | | | | Interest Rate | | | | |
| | | Commodity | | Commodity | | and Foreign | | | | | | | | | | | and Foreign | | | | |
Balance Sheet Location | Balance Sheet Location | | (a) | | (a) | | Currency (a) | | Other (a) (b) | | Total | Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Currency (a) | | Other (a) (b) | | Total |
| | | (in thousands) | | | (in thousands) |
Current Risk Management Assets | Current Risk Management Assets | | $ | 14,885 | | $ | 179 | | $ | - | | $ | (12,688) | | $ | 2,376 | Current Risk Management Assets | | $ | 19,174 | | $ | 134 | | $ | 13,558 | | $ | (18,641) | | $ | 14,225 |
Long-term Risk Management Assets | Long-term Risk Management Assets | | | 2,640 | | | - | | | - | | | (2,590) | | | 50 | Long-term Risk Management Assets | | | 1,944 | | | - | | | - | | | (1,692) | | | 252 |
Total Assets | Total Assets | | | 17,525 | | | 179 | | | - | | | (15,278) | | | 2,426 | Total Assets | | | 21,118 | | | 134 | | | 13,558 | | | (20,333) | | | 14,477 |
| | | | | | | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | Current Risk Management Liabilities | | 14,981 | | 301 | | - | | (12,703) | | 2,579 | Current Risk Management Liabilities | | 19,607 | | - | | - | | (18,685) | | 922 |
Long-term Risk Management Liabilities | Long-term Risk Management Liabilities | | | 2,913 | | | - | | | - | | | (2,769) | | | 144 | Long-term Risk Management Liabilities | | | 1,889 | | | - | | | - | | | (1,692) | | | 197 |
Total Liabilities | Total Liabilities | | | 17,894 | | | 301 | | | - | | | (15,472) | | | 2,723 | Total Liabilities | | | 21,496 | | | - | | | - | | | (20,377) | | | 1,119 |
| | | | | | | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net | Total MTM Derivative Contract Net | | | | | | | | | | | | Total MTM Derivative Contract Net | | | | | | | | | | | |
| Assets (Liabilities) | | $ | (369) | | $ | (122) | | $ | - | | $ | 194 | | $ | (297) | Assets (Liabilities) | | $ | (378) | | $ | 134 | | $ | 13,558 | | $ | 44 | | $ | 13,358 |
Fair Value of Derivative Instruments |
September 30, 2010 |
| | | | | | | | | | | | | | | | |
SWEPCo | | | | | | | | | | | | | | | |
| | | Risk | | | | | | | | |
| | | Management | | | | | | | | |
| | | Contracts | | Hedging Contracts | | | | |
| | | | | | | | Interest Rate | | | | |
| | | Commodity | | Commodity | | and Foreign | | | | |
Balance Sheet Location | | (a) | | (a) | | Currency (a) | | Other (a) (b) | | Total |
| | | (in thousands) |
Current Risk Management Assets | | $ | 12,973 | | $ | 48 | | $ | 2 | | $ | (11,006) | | $ | 2,017 |
Long-term Risk Management Assets | | | 3,027 | | | 3 | | | 6 | | | (2,617) | | | 419 |
Total Assets | | | 16,000 | | | 51 | | | 8 | | | (13,623) | | | 2,436 |
| | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | | | 11,431 | | | 37 | | | 87 | | | (11,032) | | | 523 |
Long-term Risk Management Liabilities | | | 2,926 | | | 6 | | | - | | | (2,660) | | | 272 |
Total Liabilities | | | 14,357 | | | 43 | | | 87 | | | (13,692) | | | 795 |
| | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net | | | | | | | | | | | | | | | |
| Assets (Liabilities) | | $ | 1,643 | | $ | 8 | | $ | (79) | | $ | 69 | | $ | 1,641 |
| | | | | | | | | | | | | | | | |
Fair Value of Derivative Instruments |
December 31, 2009 |
| | | | | | | | | | | | | | | | |
SWEPCo | | | | | | | | | | | | | | | |
| | | Risk | | | | | | | | |
| | | Management | | | | | | | | |
| | | Contracts | | Hedging Contracts | | | | |
| | | | | | | | Interest Rate | | | | |
| | | Commodity | | Commodity | | and Foreign | | | | |
Balance Sheet Location | | (a) | | (a) | | Currency (a) | | Other (a) (b) | | Total |
| | | (in thousands) |
Current Risk Management Assets | | $ | 22,847 | | $ | 169 | | $ | 42 | | $ | (20,009) | | $ | 3,049 |
Long-term Risk Management Assets | | | 4,145 | | | - | | | 5 | | | (4,066) | | | 84 |
Total Assets | | | 26,992 | | | 169 | | | 47 | | | (24,075) | | | 3,133 |
| | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | | | 20,788 | | | - | | | 89 | | | (20,033) | | | 844 |
Long-term Risk Management Liabilities | | | 4,568 | | | - | | | - | | | (4,347) | | | 221 |
Total Liabilities | | | 25,356 | | | - | | | 89 | | | (24,380) | | | 1,065 |
| | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net | | | | | | | | | | | | | | | |
| Assets (Liabilities) | | $ | 1,636 | | $ | 169 | | $ | (42) | | $ | 305 | | $ | 2,068 |
(a) | Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the Condensed Balance Sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” |
(b) | Amounts represent counterparty netting of risk management and hedging contracts, associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging” and dedesignated risk management contracts. |
Fair Value of Derivative Instruments |
March 31, 2011 |
| | | | | | | | | | | | | | | | | |
SWEPCo | | | | | | | | | | | | | | | |
| | | | Risk | | | | | | | | |
| | | | Management | | | | | | | | |
| | | | Contracts | | Hedging Contracts | | | | |
| | | | | | | | | Interest Rate | | | | |
| | | | | | | | and Foreign | | | | |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Currency (a) | | Other (a) (b) | | Total |
| | | | (in thousands) |
Current Risk Management Assets | | $ | 24,688 | | $ | 347 | | $ | 1 | | $ | (24,279) | | $ | 757 |
Long-term Risk Management Assets | | | 4,306 | | | - | | | 8 | | | (3,673) | | | 641 |
Total Assets | | | 28,994 | | | 347 | | | 9 | | | (27,952) | | | 1,398 |
| | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | | | 26,493 | | | 1 | | | - | | | (24,269) | | | 2,225 |
Long-term Risk Management Liabilities | | | 4,041 | | | - | | | - | | | (3,686) | | | 355 |
Total Liabilities | | | 30,534 | | | 1 | | | - | | | (27,955) | | | 2,580 |
| | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net | | | | | | | | | | | | | | | |
| Assets (Liabilities) | | $ | (1,540) | | $ | 346 | | $ | 9 | | $ | 3 | | $ | (1,182) |
| | | | | | | | | | | | | | | | | |
Fair Value of Derivative Instruments |
December 31, 2010 |
| | | | | | | | | | | | | | | | | |
SWEPCo | | | | | | | | | | | | | | | |
| | | | Risk | | | | | | | | |
| | | | Management | | | | | | | | |
| | | | Contracts | | Hedging Contracts | | | | |
| | | | | | | | | Interest Rate | | | | |
| | | | | | | | and Foreign | | | | |
Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Currency (a) | | Other (a) (b) | | Total |
| | | | (in thousands) |
Current Risk Management Assets | | $ | 33,284 | | $ | 123 | | $ | - | | $ | (32,198) | | $ | 1,209 |
Long-term Risk Management Assets | | | 3,346 | | | - | | | 5 | | | (2,913) | | | 438 |
Total Assets | | | 36,630 | | | 123 | | | 5 | | | (35,111) | | | 1,647 |
| | | | | | | | | | | | | | | | | |
Current Risk Management Liabilities | | | 36,338 | | | - | | | - | | | (32,271) | | | 4,067 |
Long-term Risk Management Liabilities | | | 3,250 | | | - | | | - | | | (2,912) | | | 338 |
Total Liabilities | | | 39,588 | | | - | | | - | | | (35,183) | | | 4,405 |
| | | | | | | | | | | | | | | | | |
Total MTM Derivative Contract Net | | | | | | | | | | | | | | | |
| Assets (Liabilities) | | $ | (2,958) | | $ | 123 | | $ | 5 | | $ | 72 | | $ | (2,758) |
| | | | | | | | | | | | | | | | | |
(a) | Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the Condensed Balance Sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." |
(b) | Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." Amounts also include dedesignated risk management contracts. |
The tables below presentspresent the Registrant Subsidiaries’ activity of derivative risk management contracts for the three and nine months ended September 30, 2010March 31, 2011 and 2009:2010:
Amount of Gain (Loss) Recognized on | Amount of Gain (Loss) Recognized on | Amount of Gain (Loss) Recognized on | |
Risk Management Contracts | Risk Management Contracts | Risk Management Contracts | |
For the Three Months Ended September 30, 2010 | |
For the Three Months Ended March 31, 2011 | | For the Three Months Ended March 31, 2011 | |
| | | |
Location of Gain (Loss) | Location of Gain (Loss) | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo | |
| | | (in thousands) | (in thousands) | |
Electric Generation, Transmission and | Electric Generation, Transmission and | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Distribution Revenues | | $ | 1,938 | | $ | 6,436 | | $ | 6,374 | | $ | 5,378 | | $ | 686 | | $ | 1,123 | |
Distribution Revenues | | | $ | 1,816 | | | $ | 4,790 | | | $ | 5,415 | | | $ | 5,800 | | | $ | 119 | | | $ | 123 | |
Sales to AEP Affiliates | Sales to AEP Affiliates | | (522) | | (704) | | (571) | | 2,605 | | (204) | | (486) | | | 20 | | | | 13 | | | | 17 | | | | 19 | | | | 1 | | | | 1 | |
Regulatory Assets (a) | Regulatory Assets (a) | | - | | (2,013) | | - | | (4,064) | | 16 | | - | | | 373 | | | | 88 | | | | 186 | | | | 307 | | | | (368 | ) | | | 1,642 | |
Regulatory Liabilities (a) | Regulatory Liabilities (a) | | | 4,538 | | | - | | | 1,956 | | | - | | | 999 | | | 893 | | | 6,754 | | | | - | | | | 360 | | | | (105 | ) | | | 392 | | | | 340 | |
Total Gain (Loss) on Risk Management | Total Gain (Loss) on Risk Management | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Contracts | | $ | 5,954 | | $ | 3,719 | | $ | 7,759 | | $ | 3,919 | | $ | 1,497 | | $ | 1,530 | |
Contracts | | | $ | 8,963 | | | $ | 4,891 | | | $ | 5,978 | | | $ | 6,021 | | | $ | 144 | | | $ | 2,106 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Amount of Gain (Loss) Recognized on | Amount of Gain (Loss) Recognized on | Amount of Gain (Loss) Recognized on | |
Risk Management Contracts | Risk Management Contracts | Risk Management Contracts | |
For the Three Months Ended September 30, 2009 | |
For the Three Months Ended March 31, 2010 | | For the Three Months Ended March 31, 2010 | |
| | | |
Location of Gain (Loss) | Location of Gain (Loss) | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo | |
| | | (in thousands) | (in thousands) | |
Electric Generation, Transmission and | Electric Generation, Transmission and | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Distribution Revenues | | $ | 2,240 | | $ | 6,551 | | $ | 7,127 | | $ | 3,155 | | $ | (850) | | $ | (1,067) | |
Distribution Revenues | | | $ | 4,173 | | | $ | 9,607 | | | $ | 6,885 | | | $ | 10,221 | | | $ | 683 | | | $ | 788 | |
Sales to AEP Affiliates | Sales to AEP Affiliates | | (237) | | (238) | | (292) | | 302 | | 1,135 | | 1,347 | | | (2,361 | ) | | | (1,562 | ) | | | (1,443 | ) | | | 253 | | | | (176 | ) | | | (308 | ) |
Regulatory Assets (a) | Regulatory Assets (a) | | - | | (2,616) | | (1,278) | | (2,922) | | (617) | | (20) | | | - | | | | - | | | | - | | | | - | | | | 331 | | | | (47 | ) |
Regulatory Liabilities (a) | Regulatory Liabilities (a) | | | 10,199 | | | 4,774 | | | 3,369 | | | 5,384 | | | (480) | | | 9 | | | 17,027 | | | | 3,681 | | | | 15,092 | | | | 4,093 | | | | 2,638 | | | | (1,011 | ) |
Total Gain (Loss) on Risk Management | Total Gain (Loss) on Risk Management | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Contracts | | | $ | 18,839 | | | $ | 11,726 | | | $ | 20,534 | | | $ | 14,567 | | | $ | 3,476 | | | $ | (578 | ) |
| Contracts | | $ | 12,202 | | $ | 8,471 | | $ | 8,926 | | $ | 5,919 | | $ | (812) | | $ | 269 | | | | | | | | | | | | | | | | | | | | | | | | |
(a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheet. | | (a)Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheet. | |
Amount of Gain (Loss) Recognized on |
Risk Management Contracts |
For the Nine Months Ended September 30, 2010 |
|
Location of Gain (Loss) | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
Electric Generation, Transmission and | | | | | | | | | | | | | | | | | | |
| Distribution Revenues | | $ | 4,419 | | $ | 19,513 | | $ | 15,762 | | $ | 17,609 | | $ | 1,716 | | $ | 2,524 |
Sales to AEP Affiliates | | | (2,098) | | | (2,153) | | | (1,913) | | | 5,014 | | | (502) | | | (1,024) |
Regulatory Assets (a) | | | - | | | (3,557) | | | - | | | (5,725) | | | 321 | | | 73 |
Regulatory Liabilities (a) | | | 19,686 | | | - | | | 10,418 | | | - | | | 3,763 | | | 1,406 |
Total Gain (Loss) on Risk Management | | | | | | | | | | | | | | | | | | |
| Contracts | | $ | 22,007 | | $ | 13,803 | | $ | 24,267 | | $ | 16,898 | | $ | 5,298 | | $ | 2,979 |
| | | | | | | | | | | | | | | | | | | |
Amount of Gain (Loss) Recognized on |
Risk Management Contracts |
For the Nine Months Ended September 30, 2009 |
|
Location of Gain (Loss) | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
Electric Generation, Transmission and | | | | | | | | | | | | | | | | | | |
| Distribution Revenues | | $ | 13,211 | | $ | 26,557 | | $ | 31,333 | | $ | 27,453 | | $ | (2) | | $ | 151 |
Sales to AEP Affiliates | | | (7,563) | | | (4,707) | | | (4,710) | | | (1,191) | | | 510 | | | 372 |
Regulatory Assets (a) | | | - | | | (6,243) | | | (3,727) | | | (7,231) | | | (283) | | | 200 |
Regulatory Liabilities (a) | | | 24,479 | | | 2,284 | | | 4,347 | | | 2,300 | | | (1,696) | | | (65) |
Total Gain (Loss) on Risk Management | | | | | | | | | | | | | | | | | | |
| Contracts | | $ | 30,127 | | $ | 17,891 | | $ | 27,243 | | $ | 21,331 | | $ | (1,471) | | $ | 658 |
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or non-current on the balance sheet.
Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on 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 on 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 some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO the non-Texas portion of SWEPCo generation and beginning in the second quarter of 2009 the Texas portion of SWEPCo generation)SWEPCo) for both tradi ngtrading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” SWEPCo re-applied the accounting guidance for “Regulated Operations” for the generation portion of SWEPCo’s Texas retail jurisdiction effective the second quarter of 2009.
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 the offsetting gain or loss on the hedged item associated with the hedged risk inimpacts Net Income during the period of change.
The Registrant Subsidiaries record realized and unrealized 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 the Condensed Statements of Income. During the three and nine months ended September 30,March 31, 2011 and 2010, and 2009, the Registrant Subsidiaries did not employ any fair value hedging strategies.
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 derivative contracts for the purchase and sale of power, coal, natural gas and heating oil and gasoline designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the Condensed Statements of Income, or in Regulatory Assets or Regulatory Liabilities on the Condensed Balance Sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30,March 31, 2011 and 2010, and 2009, APCo, CSPCo, I&M and OPCo designated commodity derivatives as cash flow hedges.
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 expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the Condensed Statements of Income. During the three and nine months ended September 30, 2010,March 31, 2011, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedging strategies of forecasted fuel purchases.
hedges.
The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financingfinancings from Accumulated Other Comprehensive Income (Loss) into Interest Expense in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2010,March 31, 2011, APCo and PSO designated interest rate derivatives as cash flow hedges. During the three and nine months ended September 30, 2009, OPCoMarch 31, 2010, APCo designated interest rate derivatives as cash flow hedges.
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 on 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. During the three and nine months ended September 30,March 31, 2011 and 2010, and 2009, SWEPCo designated foreign currency derivatives as cash flow hedges.
During the three and nine months ended September 30,March 31, 2011 and 2010, and 2009, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.
The following tables providesprovide details on designated, effective cash flow hedges included in AOCIAccumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2010March 31, 2011 and 2009.2010. All amounts in the following tables are presented net of related income taxes.
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | For the Three Months Ended September 30, 2010 | |
For the Three Months Ended March 31, 2011 | | For the Three Months Ended March 31, 2011 |
| Commodity Contracts | Commodity Contracts | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo | Commodity Contracts | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) | | | (in thousands) |
Balance in AOCI as of June 30, 2010 | | $ | (1,437) | | $ | (807) | | $ | (813) | | $ | (941) | | $ | (84) | | $ | (33) | |
Balance in AOCI as of December 31, 2010 | | Balance in AOCI as of December 31, 2010 | | $ | (273) | | $ | (134) | | $ | (178) | | $ | (230) | | $ | 88 | | $ | 82 |
Changes in Fair Value Recognized in AOCI | Changes in Fair Value Recognized in AOCI | | (1,212) | | (729) | | (776) | | (914) | | 69 | | 60 | Changes in Fair Value Recognized in AOCI | | 178 | | 12 | | 78 | | 195 | | 212 | | 194 |
Amount of (Gain) or Loss Reclassified | Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | | Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | |
| from AOCI to Income Statement/within | | | | | | | | | | | | | from AOCI to Income Statement/within | | | | | | | | | | | | |
| Balance Sheet: | | | | | | | | | | | | | Balance Sheet: | | | | | | | | | | | | |
| | Electric Generation, Transmission, and | | | | | | | | | | | | | | Electric Generation, Transmission, and | | | | | | | | | | | | |
| | Distribution Revenues | | 60 | | 159 | | 127 | | 184 | | - | | - | | Distribution Revenues | | (4) | | (12) | | (10) | | (14) | | - | | - |
| | Fuel and Other Consumables Used for | | | | | | | | | | | | | | Fuel and Other Consumables Used for | | | | | | | | | | | | |
| | Electric Generation | | - | | - | | - | | - | | 40 | | - | | Electric Generation | | - | | - | | - | | - | | - | | - |
| | Purchased Electricity for Resale | | 56 | | 156 | | 138 | | 195 | | - | | - | | Purchased Electricity for Resale | | 87 | | 237 | | 194 | | 284 | | - | | - |
| | Other Operation Expense | | (7) | | (5) | | (5) | | (6) | | (7) | | (7) | | Other Operation Expense | | (13) | | (9) | | (9) | | (14) | | (13) | | (13) |
| | Maintenance Expense | | (11) | | (3) | | (5) | | (6) | | (4) | | (3) | | Maintenance Expense | | (25) | | (6) | | (10) | | (13) | | (7) | | (8) |
| | Property, Plant and Equipment | | (11) | | (4) | | (5) | | (9) | | (7) | | (5) | | Property, Plant and Equipment | | (23) | | (9) | | (11) | | (18) | | (16) | | (11) |
| | Regulatory Assets (a) | | 436 | | - | | 58 | | - | | - | | - | | Regulatory Assets (a) | | 311 | | - | | 47 | | - | | - | | - |
| | Regulatory Liabilities (a) | | | - | | | - | | | - | | | - | | | - | | | - | | Regulatory Liabilities (a) | | | - | | | - | | | - | | | - | | | - | | | - |
Balance in AOCI as of September 30, 2010 | | $ | (2,126) | | $ | (1,233) | | $ | (1,281) | | $ | (1,497) | | $ | 7 | | $ | 12 | |
Balance in AOCI as of March 31, 2011 | | Balance in AOCI as of March 31, 2011 | | $ | 238 | | $ | 79 | | $ | 101 | | $ | 190 | | $ | 264 | | $ | 244 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Interest Rate and Foreign Currency | | | | | | | | | | | | | |
Contracts | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo | |
Interest Rate and Foreign Currency Contracts | | Interest Rate and Foreign Currency Contracts | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in thousands) | | | | (in thousands) |
Balance in AOCI as of June 30, 2010 | | $ | (8,298) | | $ | - | | $ | (9,011) | | $ | 11,492 | | $ | (443) | | $ | (4,812) | |
Balance in AOCI as of December 31, 2010 | | Balance in AOCI as of December 31, 2010 | | $ | 217 | | $ | - | | $ | (8,507) | | $ | 10,813 | | $ | 8,406 | | $ | (4,272) |
Changes in Fair Value Recognized in AOCI | Changes in Fair Value Recognized in AOCI | | (790) | | - | | - | | 1 | | - | | 122 | Changes in Fair Value Recognized in AOCI | | (373) | | - | | - | | - | | (476) | | 7 |
Amount of (Gain) or Loss Reclassified | Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | | Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | |
| from AOCI to Income Statement/within | | | | | | | | | | | | | from AOCI to Income Statement/within | | | | | | | | | | | | |
| Balance Sheet: | | | | | | | | | | | | | Balance Sheet: | | | | | | | | | | | | |
| | Depreciation and Amortization | | | | | | | | | | | | | | Depreciation and Amortization | | | | | | | | | | | | |
| | Expense | | - | | - | | - | | 1 | | - | | - | | Expense | | - | | - | | - | | 1 | | - | | - |
| | Other Operation Expense | | - | | - | | - | | - | | - | | (3) | | Other Operation Expense | | - | | - | | - | | - | | - | | - |
| | Interest Expense | | | 394 | | | - | | | 252 | | | (341) | | | 18 | | | 207 | | Interest Expense | | | 373 | | | - | | | 252 | | | (341) | | | (143) | | | 207 |
Balance in AOCI as of September 30, 2010 | | $ | (8,694) | | $ | - | | $ | (8,759) | | $ | 11,153 | | $ | (425) | | $ | (4,486) | |
Balance in AOCI as of March 31, 2011 | | Balance in AOCI as of March 31, 2011 | | $ | 217 | | $ | - | | $ | (8,255) | | $ | 10,473 | | $ | 7,787 | | $ | (4,058) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Contracts | Total Contracts | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo | Total Contracts | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in thousands) | | | | (in thousands) |
Balance in AOCI as of June 30, 2010 | | $ | (9,735) | | $ | (807) | | $ | (9,824) | | $ | 10,551 | | $ | (527) | | $ | (4,845) | |
Balance in AOCI as of December 31, 2010 | | Balance in AOCI as of December 31, 2010 | | $ | (56) | | $ | (134) | | $ | (8,685) | | $ | 10,583 | | $ | 8,494 | | $ | (4,190) |
Changes in Fair Value Recognized in AOCI | Changes in Fair Value Recognized in AOCI | | (2,002) | | (729) | | (776) | | (913) | | 69 | | 182 | Changes in Fair Value Recognized in AOCI | | (195) | | 12 | | 78 | | 195 | | (264) | | 201 |
Amount of (Gain) or Loss Reclassified | Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | | Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | |
| from AOCI to Income Statement/within | | | | | | | | | | | | | from AOCI to Income Statement/within | | | | | | | | | | | | |
| Balance Sheet: | | | | | | | | | | | | | Balance Sheet: | | | | | | | | | | | | |
| | Electric Generation, Transmission, and | | | | | | | | | | | | | | Electric Generation, Transmission, and | | | | | | | | | | | | |
| | Distribution Revenues | | 60 | | 159 | | 127 | | 184 | | - | | - | | Distribution Revenues | | (4) | | (12) | | (10) | | (14) | | - | | - |
| | Fuel and Other Consumables Used for | | | | | | | | | | | | | | Fuel and Other Consumables Used for | | | | | | | | | | | | |
| | Electric Generation | | - | | - | | - | | - | | 40 | | - | | Electric Generation | | - | | - | | - | | - | | - | | - |
| | Purchased Electricity for Resale | | 56 | | 156 | | 138 | | 195 | | - | | - | | Purchased Electricity for Resale | | 87 | | 237 | | 194 | | 284 | | - | | - |
| | Other Operation Expense | | (7) | | (5) | | (5) | | (6) | | (7) | | (10) | | Other Operation Expense | | (13) | | (9) | | (9) | | (14) | | (13) | | (13) |
| | Maintenance Expense | | (11) | | (3) | | (5) | | (6) | | (4) | | (3) | | Maintenance Expense | | (25) | | (6) | | (10) | | (13) | | (7) | | (8) |
| | Depreciation and Amortization | | | | | | | | | | | | | | Depreciation and Amortization | | | | | | | | | | | | |
| | Expense | | - | | - | | - | | 1 | | - | | - | | Expense | | - | | - | | - | | 1 | | - | | - |
| | Interest Expense | | 394 | | - | | 252 | | (341) | | 18 | | 207 | | Interest Expense | | 373 | | - | | 252 | | (341) | | (143) | | 207 |
| | Property, Plant and Equipment | | (11) | | (4) | | (5) | | (9) | | (7) | | (5) | | Property, Plant and Equipment | | (23) | | (9) | | (11) | | (18) | | (16) | | (11) |
| | Regulatory Assets (a) | | 436 | | - | | 58 | | - | | - | | - | | Regulatory Assets (a) | | 311 | | - | | 47 | | - | | - | | - |
| | Regulatory Liabilities (a) | | | - | | | - | | | - | | | - | | | - | | | - | | Regulatory Liabilities (a) | | | - | | | - | | | - | | | - | | | - | | | - |
Balance in AOCI as of September 30, 2010 | | $ | (10,820) | | $ | (1,233) | | $ | (10,040) | | $ | 9,656 | | $ | (418) | | $ | (4,474) | |
Balance in AOCI as of March 31, 2011 | | Balance in AOCI as of March 31, 2011 | | $ | 455 | | $ | 79 | | $ | (8,154) | | $ | 10,663 | | $ | 8,051 | | $ | (3,814) |
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | For the Three Months Ended September 30, 2009 | |
For the Three Months Ended March 31, 2010 | | For the Three Months Ended March 31, 2010 |
| Commodity Contracts | Commodity Contracts | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo | Commodity Contracts | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) | | | (in thousands) |
Balance in AOCI as of June 30, 2009 | | $ | 2,296 | | $ | 1,189 | | $ | 1,170 | | $ | 1,526 | | $ | 127 | | $ | 141 | |
Balance in AOCI as of December 31, 2009 | | Balance in AOCI as of December 31, 2009 | | $ | (743) | | $ | (376) | | $ | (382) | | $ | (366) | | $ | (78) | | $ | 112 |
Changes in Fair Value Recognized in AOCI | Changes in Fair Value Recognized in AOCI | | (451) | | (232) | | (227) | | (346) | | (377) | | (45) | Changes in Fair Value Recognized in AOCI | | (2,499) | | (1,457) | | (1,471) | | (1,670) | | 86 | | 3 |
Amount of (Gain) or Loss Reclassified | Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | | Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | |
| from AOCI to Income Statement/within | | | | | | | | | | | | | from AOCI to Income Statement/within | | | | | | | | | | | | |
| Balance Sheet: | | | | | | | | | | | | | Balance Sheet: | | | | | | | | | | | | |
| | Electric Generation, Transmission, and | | | | | | | | | | | | | | Electric Generation, Transmission, and | | | | | | | | | | | | |
| | Distribution Revenues | | (720) | | (1,815) | | (1,385) | | (2,126) | | - | | - | | Distribution Revenues | | 26 | | 65 | | 54 | | 76 | | - | | - |
| | Fuel and Other Consumables Used for | | | | | | | | | | | | | | Fuel and Other Consumables Used for | | | | | | | | | | | | |
| | Electric Generation | | (39) | | (17) | | (20) | | (27) | | (20) | | (22) | | Electric Generation | | - | | - | | - | | (9) | | - | | - |
| | Purchased Electricity for Resale | | 444 | | 1,116 | | 852 | | 1,313 | | - | | - | | Purchased Electricity for Resale | | 146 | | 382 | | 316 | | 440 | | - | | - |
| | Other Operation Expense | | - | | - | | - | | - | | - | | - | | Other Operation Expense | | (6) | | (8) | | (6) | | (5) | | (6) | | (7) |
| | Maintenance Expense | | - | | - | | - | | - | | - | | - | | Maintenance Expense | | (14) | | (6) | | (5) | | (4) | | (4) | | (4) |
| | Property, Plant and Equipment | | (23) | | (9) | | (12) | | (17) | | (12) | | (9) | | Property, Plant and Equipment | | (9) | | (7) | | (5) | | (5) | | (6) | | (4) |
| | Regulatory Assets (a) | | 1,664 | | - | | 226 | | - | | - | | - | | Regulatory Assets (a) | | 648 | | - | | 81 | | - | | - | | - |
| | Regulatory Liabilities (a) | | | (2,709) | | | - | | | (369) | | | - | | | - | | | - | | Regulatory Liabilities (a) | | | - | | | - | | | - | | | - | | | - | | | - |
Balance in AOCI as of September 30, 2009 | | $ | 462 | | $ | 232 | | $ | 235 | | $ | 323 | | $ | (282) | | $ | 65 | |
Balance in AOCI as of March 31, 2010 | | Balance in AOCI as of March 31, 2010 | | $ | (2,451) | | $ | (1,407) | | $ | (1,418) | | $ | (1,543) | | $ | (8) | | $ | 100 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Interest Rate and Foreign Currency | | | | | | | | | | | | | |
Contracts | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo | |
Interest Rate and Foreign Currency Contracts | | Interest Rate and Foreign Currency Contracts | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in thousands) | | | | (in thousands) |
Balance in AOCI as of June 30, 2009 | | $ | (7,285) | | $ | - | | $ | (10,017) | | $ | 16,662 | | $ | (613) | | $ | (5,497) | |
Balance in AOCI as of December 31, 2009 | | Balance in AOCI as of December 31, 2009 | | $ | (6,450) | | $ | - | | $ | (9,514) | | $ | 12,172 | | $ | (521) | | $ | (5,047) |
Changes in Fair Value Recognized in AOCI | Changes in Fair Value Recognized in AOCI | | - | | - | | - | | (4,038) | | - | | 82 | Changes in Fair Value Recognized in AOCI | | (456) | | - | | - | | - | | - | | (107) |
Amount of (Gain) or Loss Reclassified | Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | | Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | |
| from AOCI to Income Statement/within | | | | | | | | | | | | | from AOCI to Income Statement/within | | | | | | | | | | | | |
| Balance Sheet: | | | | | | | | | | | | | Balance Sheet: | | | | | | | | | | | | |
| | Depreciation and Amortization | | | | | | | | | | | | | | Depreciation and Amortization | | | | | | | | | | | | |
| | Expense | | - | | - | | (2) | | 1 | | - | | - | | Expense | | - | | - | | - | | 1 | | - | | - |
| | Interest Expense | | | 418 | | | - | | | 253 | | | (113) | | | 46 | | | 208 | | Interest Expense | | | 418 | | | - | | | 252 | | | (341) | | | 46 | | | 207 |
Balance in AOCI as of September 30, 2009 | | $ | (6,867) | | $ | - | | $ | (9,766) | | $ | 12,512 | | $ | (567) | | $ | (5,207) | |
Balance in AOCI as of March 31, 2010 | | Balance in AOCI as of March 31, 2010 | | $ | (6,488) | | $ | - | | $ | (9,262) | | $ | 11,832 | | $ | (475) | | $ | (4,947) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Contracts | Total Contracts | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo | Total Contracts | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in thousands) | | | | (in thousands) |
Balance in AOCI as of June 30, 2009 | | $ | (4,989) | | $ | 1,189 | | $ | (8,847) | | $ | 18,188 | | $ | (486) | | $ | (5,356) | |
Balance in AOCI as of December 31, 2009 | | Balance in AOCI as of December 31, 2009 | | $ | (7,193) | | $ | (376) | | $ | (9,896) | | $ | 11,806 | | $ | (599) | | $ | (4,935) |
Changes in Fair Value Recognized in AOCI | Changes in Fair Value Recognized in AOCI | | (451) | | (232) | | (227) | | (4,384) | | (377) | | 37 | Changes in Fair Value Recognized in AOCI | | (2,955) | | (1,457) | | (1,471) | | (1,670) | | 86 | | (104) |
Amount of (Gain) or Loss Reclassified | Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | | Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | |
| from AOCI to Income Statement/within | | | | | | | | | | | | | from AOCI to Income Statement/within | | | | | | | | | | | | |
| Balance Sheet: | | | | | | | | | | | | | Balance Sheet: | | | | | | | | | | | | |
| | Electric Generation, Transmission, and | | | | | | | | | | | | | | Electric Generation, Transmission, and | | | | | | | | | | | | |
| | Distribution Revenues | | (720) | | (1,815) | | (1,385) | | (2,126) | | - | | - | | Distribution Revenues | | 26 | | 65 | | 54 | | 76 | | - | | - |
| | Fuel and Other Consumables Used for | | | | | | | | | | | | | | Fuel and Other Consumables Used for | | | | | | | | | | | | |
| | Electric Generation | | (39) | | (17) | | (20) | | (27) | | (20) | | (22) | | Electric Generation | | - | | - | | - | | (9) | | - | | - |
| | Purchased Electricity for Resale | | 444 | | 1,116 | | 852 | | 1,313 | | - | | - | | Purchased Electricity for Resale | | 146 | | 382 | | 316 | | 440 | | - | | - |
| | Other Operation Expense | | - | | - | | - | | - | | - | | - | | Other Operation Expense | | (6) | | (8) | | (6) | | (5) | | (6) | | (7) |
| | Maintenance Expense | | - | | - | | - | | - | | - | | - | | Maintenance Expense | | (14) | | (6) | | (5) | | (4) | | (4) | | (4) |
| | Depreciation and Amortization | | | | | | | | | | | | | | Depreciation and Amortization | | | | | | | | | | | | |
| | Expense | | - | | - | | (2) | | 1 | | - | | - | | Expense | | - | | - | | - | | 1 | | - | | - |
| | Interest Expense | | 418 | | - | | 253 | | (113) | | 46 | | 208 | | Interest Expense | | 418 | | - | | 252 | | (341) | | 46 | | 207 |
| | Property, Plant and Equipment | | (23) | | (9) | | (12) | | (17) | | (12) | | (9) | | Property, Plant and Equipment | | (9) | | (7) | | (5) | | (5) | | (6) | | (4) |
| | Regulatory Assets (a) | | 1,664 | | - | | 226 | | - | | - | | - | | Regulatory Assets (a) | | 648 | | - | | 81 | | - | | - | | - |
| | Regulatory Liabilities (a) | | | (2,709) | | | - | | | (369) | | | - | | | - | | | - | | Regulatory Liabilities (a) | | | - | | | - | | | - | | | - | | | - | | | - |
Balance in AOCI as of September 30, 2009 | | $ | (6,405) | | $ | 232 | | $ | (9,531) | | $ | 12,835 | | $ | (849) | | $ | (5,142) | |
Balance in AOCI as of March 31, 2010 | | Balance in AOCI as of March 31, 2010 | | $ | (8,939) | | $ | (1,407) | | $ | (10,680) | | $ | 10,289 | | $ | (483) | | $ | (4,847) |
| | | | | | | | | | | | | | |
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges |
For the Nine Months Ended September 30, 2010 |
|
Commodity Contracts | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in thousands) |
Balance in AOCI as of December 31, 2009 | | $ | (743) | | $ | (376) | | $ | (382) | | $ | (366) | | $ | (78) | | $ | 112 |
Changes in Fair Value Recognized in AOCI | | | (3,069) | | | (1,806) | | | (1,859) | | | (2,214) | | | (36) | | | (36) |
Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | | | | | | | |
| from AOCI to Income Statement/within | | | | | | | | | | | | | | | | | | |
| Balance Sheet: | | | | | | | | | | | | | | | | | | |
| | Electric Generation, Transmission, and | | | | | | | | | | | | | | | | | | |
| | | Distribution Revenues | | | 117 | | | 303 | | | 247 | | | 351 | | | - | | | - |
| | Fuel and Other Consumables Used for | | | | | | | | | | | | | | | | | | |
| | | Electric Generation | | | - | | | - | | | - | | | (13) | | | 190 | | | - |
| | Purchased Electricity for Resale | | | 267 | | | 706 | | | 593 | | | 828 | | | - | | | - |
| | Other Operation Expense | | | (31) | | | (24) | | | (22) | | | (26) | | | (26) | | | (30) |
| | Maintenance Expense | | | (47) | | | (15) | | | (19) | | | (21) | | | (16) | | | (15) |
| | Property, Plant and Equipment | | | (44) | | | (21) | | | (22) | | | (31) | | | (27) | | | (19) |
| | Regulatory Assets (a) | | | 1,424 | | | - | | | 183 | | | - | | | - | | | - |
| | Regulatory Liabilities (a) | | | - | | | - | | | - | | | (5) | | | - | | | - |
Balance in AOCI as of September 30, 2010 | | $ | (2,126) | | $ | (1,233) | | $ | (1,281) | | $ | (1,497) | | $ | 7 | | $ | 12 |
| | | | | | | | | | | | | | | | | | | | | |
Interest Rate and Foreign Currency | | | | | | | | | | | | | | | | | | |
Contracts | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | (in thousands) |
Balance in AOCI as of December 31, 2009 | | $ | (6,450) | | $ | - | | $ | (9,514) | | $ | 12,172 | | $ | (521) | | $ | (5,047) |
Changes in Fair Value Recognized in AOCI | | | (3,475) | | | - | | | - | | | 1 | | | - | | | (81) |
Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | | | | | | | |
| from AOCI to Income Statement/within | | | | | | | | | | | | | | | | | | |
| Balance Sheet: | | | | | | | | | | | | | | | | | | |
| | Depreciation and Amortization | | | | | | | | | | | | | | | | | | |
| | | Expense | | | - | | | - | | | - | | | 3 | | | - | | | - |
| | Other Operation Expense | | | - | | | - | | | - | | | - | | | - | | | 21 |
| | Interest Expense | | | 1,231 | | | - | | | 755 | | | (1,023) | | | 96 | | | 621 |
Balance in AOCI as of September 30, 2010 | | $ | (8,694) | | $ | - | | $ | (8,759) | | $ | 11,153 | | $ | (425) | | $ | (4,486) |
| | | | | | | | | | | | | | | | | | | | | |
Total Contracts | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | (in thousands) |
Balance in AOCI as of December 31, 2009 | | $ | (7,193) | | $ | (376) | | $ | (9,896) | | $ | 11,806 | | $ | (599) | | $ | (4,935) |
Changes in Fair Value Recognized in AOCI | | | (6,544) | | | (1,806) | | | (1,859) | | | (2,213) | | | (36) | | | (117) |
Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | | | | | | | |
| from AOCI to Income Statement/within | | | | | | | | | | | | | | | | | | |
| Balance Sheet: | | | | | | | | | | | | | | | | | | |
| | Electric Generation, Transmission, and | | | | | | | | | | | | | | | | | | |
| | | Distribution Revenues | | | 117 | | | 303 | | | 247 | | | 351 | | | - | | | - |
| | Fuel and Other Consumables Used for | | | | | | | | | | | | | | | | | | |
| | | Electric Generation | | | - | | | - | | | - | | | (13) | | | 190 | | | - |
| | Purchased Electricity for Resale | | | 267 | | | 706 | | | 593 | | | 828 | | | - | | | - |
| | Other Operation Expense | | | (31) | | | (24) | | | (22) | | | (26) | | | (26) | | | (9) |
| | Maintenance Expense | | | (47) | | | (15) | | | (19) | | | (21) | | | (16) | | | (15) |
| | Depreciation and Amortization | | | | | | | | | | | | | | | | | | |
| | | Expense | | | - | | | - | | | - | | | 3 | | | - | | | - |
| | Interest Expense | | | 1,231 | | | - | | | 755 | | | (1,023) | | | 96 | | | 621 |
| | Property, Plant and Equipment | | | (44) | | | (21) | | | (22) | | | (31) | | | (27) | | | (19) |
| | Regulatory Assets (a) | | | 1,424 | | | - | | | 183 | | | - | | | - | | | - |
| | Regulatory Liabilities (a) | | | - | | | - | | | - | | | (5) | | | - | | | - |
Balance in AOCI as of September 30, 2010 | | $ | (10,820) | | $ | (1,233) | | $ | (10,040) | | $ | 9,656 | | $ | (418) | | $ | (4,474) |
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges |
For the Nine Months Ended September 30, 2009 |
|
Commodity Contracts | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in thousands) |
Balance in AOCI as of December 31, 2008 | | $ | 2,726 | | $ | 1,531 | | $ | 1,482 | | $ | 1,898 | | $ | - | | $ | - |
Changes in Fair Value Recognized in AOCI | | | (278) | | | (257) | | | (233) | | | (325) | | | (246) | | | 100 |
Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | | | | | | | |
| from AOCI to Income Statement/within | | | | | | | | | | | | | | | | | | |
| Balance Sheet: | | | | | | | | | | | | | | | | | | |
| | Electric Generation, Transmission, and | | | | | | | | | | | | | | | | | | |
| | | Distribution Revenues | | | (1,429) | | | (3,586) | | | (2,774) | | | (4,319) | | | - | | | - |
| | Fuel and Other Consumables Used for | | | | | | | | | | | | | | | | | | |
| | | Electric Generation | | | (45) | | | (21) | | | (24) | | | (32) | | | (23) | | | (25) |
| | Purchased Electricity for Resale | | | 1,038 | | | 2,576 | | | 2,033 | | | 3,120 | | | - | | | - |
| | Other Operation Expense | | | - | | | - | | | - | | | - | | | - | | | - |
| | Maintenance Expense | | | - | | | - | | | - | | | - | | | - | | | - |
| | Property, Plant and Equipment | | | (26) | | | (11) | | | (13) | | | (19) | | | (13) | | | (10) |
| | Regulatory Assets (a) | | | 3,800 | | | - | | | 457 | | | - | | | - | | | - |
| | Regulatory Liabilities (a) | | | (5,324) | | | - | | | (693) | | | - | | | - | | | - |
Balance in AOCI as of September 30, 2009 | | $ | 462 | | $ | 232 | | $ | 235 | | $ | 323 | | $ | (282) | | $ | 65 |
| | | | | | | | | | | | | | | | | | | | | |
Interest Rate and Foreign Currency | | | | | | | | | | | | | | | | | | |
Contracts | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | (in thousands) |
Balance in AOCI as of December 31, 2008 | | $ | (8,118) | | $ | - | | $ | (10,521) | | $ | 1,752 | | $ | (704) | | $ | (5,924) |
Changes in Fair Value Recognized in AOCI | | | - | | | - | | | - | | | 10,915 | | | - | | | 95 |
Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | | | | | | | |
| from AOCI to Income Statement/within | | | | | | | | | | | | | | | | | | |
| Balance Sheet: | | | | | | | | | | | | | | | | | | |
| | Depreciation and Amortization | | | | | | | | | | | | | | | | | | |
| | | Expense | | | - | | | - | | | (4) | | | 3 | | | - | | | - |
| | Interest Expense | | | 1,251 | | | - | | | 759 | | | (158) | | | 137 | | | 622 |
Balance in AOCI as of September 30, 2009 | | $ | (6,867) | | $ | - | | $ | (9,766) | | $ | 12,512 | | $ | (567) | | $ | (5,207) |
| | | | | | | | | | | | | | | | | | | | | |
Total Contracts | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | (in thousands) |
Balance in AOCI as of December 31, 2008 | | $ | (5,392) | | $ | 1,531 | | $ | (9,039) | | $ | 3,650 | | $ | (704) | | $ | (5,924) |
Changes in Fair Value Recognized in AOCI | | | (278) | | | (257) | | | (233) | | | 10,590 | | | (246) | | | 195 |
Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | | | | | | | |
| from AOCI to Income Statement/within | | | | | | | | | | | | | | | | | | |
| Balance Sheet: | | | | | | | | | | | | | | | | | | |
| | Electric Generation, Transmission, and | | | | | | | | | | | | | | | | | | |
| | | Distribution Revenues | | | (1,429) | | | (3,586) | | | (2,774) | | | (4,319) | | | - | | | - |
| | Fuel and Other Consumables Used for | | | | | | | | | | | | | | | | | | |
| | | Electric Generation | | | (45) | | | (21) | | | (24) | | | (32) | | | (23) | | | (25) |
| | Purchased Electricity for Resale | | | 1,038 | | | 2,576 | | | 2,033 | | | 3,120 | | | - | | | - |
| | Other Operation Expense | | | - | | | - | | | - | | | - | | | - | | | - |
| | Maintenance Expense | | | - | | | - | | | - | | | - | | | - | | | - |
| | Depreciation and Amortization | | | | | | | | | | | | | | | | | | |
| | | Expense | | | - | | | - | | | (4) | | | 3 | | | - | | | - |
| | Interest Expense | | | 1,251 | | | - | | | 759 | | | (158) | | | 137 | | | 622 |
| | Property, Plant and Equipment | | | (26) | | | (11) | | | (13) | | | (19) | | | (13) | | | (10) |
| | Regulatory Assets (a) | | | 3,800 | | | - | | | 457 | | | - | | | - | | | - |
| | Regulatory Liabilities (a) | | | (5,324) | | | - | | | (693) | | | - | | | - | | | - |
Balance in AOCI as of September 30, 2009 | | $ | (6,405) | | $ | 232 | | $ | (9,531) | | $ | 12,835 | | $ | (849) | | $ | (5,142) |
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or non-current on the balance sheets.
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the Balance Sheets. |
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the Condensed Balance Sheets at September 30, 2010March 31, 2011 and December 31, 20092010 were:
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |
Condensed Balance Sheets | Condensed Balance Sheets | Condensed Balance Sheets | |
September 30, 2010 | |
March 31, 2011 | | March 31, 2011 | |
| | | |
| | | Hedging Assets (a) | | Hedging Liabilities (a) | | AOCI Gain (Loss) Net of Tax | | Hedging Assets (a) | | Hedging Liabilities (a) | | AOCI Gain (Loss) Net of Tax | |
| | | | | Interest Rate | | | | Interest Rate | | | | Interest Rate | | | | Interest Rate | | | | Interest Rate | | | | Interest Rate | |
| | | | | and Foreign | | | | and Foreign | | | | and Foreign | | | | and Foreign | | | | and Foreign | | | | and Foreign | |
Company | Company | | Commodity | | Currency | | Commodity | | Currency | | Commodity | | Currency | | Commodity | | Currency | | Commodity | | Currency | | Commodity | | Currency | |
| | | (in thousands) | | (in thousands) | |
APCo | APCo | | $ | 70 | | $ | - | | $ | (3,367) | | $ | (1,216) | | $ | (2,126) | | $ | (8,694) | | | $ | 947 | | | $ | - | | | $ | (697 | ) | | $ | - | | | $ | 238 | | | $ | 217 | |
CSPCo | CSPCo | | | 32 | | | - | | | (1,940) | | - | | | (1,233) | | | - | | | | 462 | | | | - | | | | (399 | ) | | | - | | | | 79 | | | | - | |
I&M | I&M | | | 37 | | - | | (2,023) | | - | | (1,281) | | (8,759) | | | | 499 | | | | - | | | | (409 | ) | | | - | | | | 101 | | | | (8,255 | ) |
OPCo | OPCo | | | 50 | | - | | (2,370) | | - | | (1,497) | | 11,153 | | | | 687 | | | | - | | | | (479 | ) | | | - | | | | 190 | | | | 10,473 | |
PSO | PSO | | 21 | | - | | | (21) | | - | | | 7 | | | (425) | | | | 376 | | | | - | | | | - | | | | - | | | | 264 | | | | 7,787 | |
SWEPCo | SWEPCo | | 19 | | 8 | | (11) | | (87) | | 12 | | (4,486) | | | | 347 | | | | 9 | | | | (1 | ) | | | - | | | | 244 | | | | (4,058 | ) |
| | | Expected to be Reclassified to | | | | | Expected to be Reclassified to | | | | |
| | | Net Income During the Next | | | | | Net Income During the Next | | | | |
| | | Twelve Months | | | | | Twelve Months | | | | |
| | | | | | | Maximum Term for | | | | | | Maximum Term for | |
| | | | | Interest Rate | | Exposure to | | | | Interest Rate | | Exposure to | |
| | | | | and Foreign | | Variability of Future | | | | and Foreign | | Variability of Future | |
Company | Company | | Commodity | | Currency | | Cash Flows | | Commodity | | Currency | | Cash Flows | |
| | | (in thousands) | | (in months) | | (in thousands) | | (in months) | |
APCo | APCo | | $ | (2,002) | | $ | (1,733) | | | 15 | | | $ | 247 | | | $ | (1,076 | ) | | | 38 | |
CSPCo | CSPCo | | | (1,161) | | | - | | | 15 | | | | 85 | | | | - | | | | 38 | |
I&M | I&M | | | (1,208) | | (1,007) | | | 15 | | | | 105 | | | | (853 | ) | | | 38 | |
OPCo | OPCo | | | (1,410) | | 1,359 | | | 15 | | | | 194 | | | | 1,359 | | | | 38 | |
PSO | PSO | | 9 | | (73) | | | 15 | | | | 255 | | | | 759 | | | | 21 | |
SWEPCo | SWEPCo | | 13 | | (829) | | | 26 | | | | 234 | | | | (829 | ) | | | 21 | |
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |
Condensed Balance Sheets | Condensed Balance Sheets | Condensed Balance Sheets | |
December 31, 2009 | |
December 31, 2010 | | December 31, 2010 | |
| | | |
| | | Hedging Assets (a) | | Hedging Liabilities (a) | | AOCI Gain (Loss) Net of Tax | | Hedging Assets (a) | | Hedging Liabilities (a) | | AOCI Gain (Loss) Net of Tax | |
| | | | | Interest Rate | | | | Interest Rate | | | | Interest Rate | | | | Interest Rate | | | | Interest Rate | | | | Interest Rate | |
| | | | | and Foreign | | | | and Foreign | | | | and Foreign | | | | and Foreign | | | | and Foreign | | | | and Foreign | |
Company | Company | | Commodity | | Currency | | Commodity | | Currency | | Commodity | | Currency | | Commodity | | Currency | | Commodity | | Currency | | Commodity | | Currency | |
| | | (in thousands) | | (in thousands) | |
APCo | APCo | | $ | 1,999 | | $ | - | | $ | (3,542) | | $ | - | | $ | (743) | | $ | (6,450) | | | $ | 333 | | | $ | 11,888 | | | $ | (727 | ) | | $ | - | | | $ | (273 | ) | | $ | 217 | |
CSPCo | CSPCo | | | 984 | | | - | | | (1,794) | | - | | | (376) | | | - | | | | 229 | | | | - | | | | (419 | ) | | | - | | | | (134 | ) | | | - | |
I&M | I&M | | | 1,011 | | - | | (1,809) | | - | | (382) | | (9,514) | | | | 175 | | | | - | | | | (437 | ) | | | - | | | | (178 | ) | | | (8,507 | ) |
OPCo | OPCo | | | 1,242 | | - | | (2,088) | | - | | (366) | | 12,172 | | | | 174 | | | | - | | | | (511 | ) | | | - | | | | (230 | ) | | | 10,813 | |
PSO | PSO | | 178 | | - | | | (300) | | - | | | (78) | | | (521) | | | | 134 | | | | 13,558 | | | | - | | | | - | | | | 88 | | | | 8,406 | |
SWEPCo | SWEPCo | | 168 | | 5 | | - | | (46) | | 112 | | (5,047) | | | | 123 | | | | 5 | | | | - | | | | - | | | | 82 | | | | (4,272 | ) |
| | | Expected to be Reclassified to | | |
| | | Net Income During the Next | | | Expected to be Reclassified to | |
| | | Twelve Months | | | Net Income During the Next | |
| | | | | | | | Twelve Months | |
| | | | | Interest Rate | | | | | Interest Rate | |
| | | | | and Foreign | | | | | and Foreign | |
Company | Company | | Commodity | | Currency | | | Commodity | | Currency | |
| | | (in thousands) | | | (in thousands) | |
APCo | APCo | | $ | (691) | | $ | (1,301) | | | | $ | (280 | ) | | $ | (1,173 | ) |
CSPCo | CSPCo | | | (349) | | | - | | | | | (137 | ) | | | - | |
I&M | I&M | | | (358) | | (1,007) | | | | | (184 | ) | | | (955 | ) |
OPCo | OPCo | | | (335) | | 1,359 | | | | | (236 | ) | | | 1,359 | |
PSO | PSO | | (79) | | (114) | | | | | 88 | | | | 735 | |
SWEPCo | SWEPCo | | 111 | | (829) | | | | | 82 | | | | (829 | ) |
(a) | Hedging Assets and Hedging Liabilities are 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
AEPSC, on behalf of the Registrant Subsidiaries, limits 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.
AEPSC, on behalf of the Registrant Subsidiaries, uses 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 fai lurefailure 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), and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional 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, AEP’s risk management organization assesses the appropriateness of these collateral triggering items in contracts. Management does not anticipate a downgrade below investment grade. The following tables representrepresent: (a) the Registrant Subsidiaries’ aggregate fair valuevalues of such derivative contracts, (b) the amount of collateral the Registrant Subs idiariesSubsidiaries would have been required to post for all derivative and non-derivative contracts if the credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of September 30, 2010March 31, 2011 and December 31, 2009:2010:
| | | September 30, 2010 | |
| | | | | | | | | | | | March 31, 2011 | |
| | | Liabilities for | | Amount of Collateral the | | Amount | | Liabilities for | | Amount of Collateral the | | Amount | |
| | | Derivative Contracts | | Registrant Subsidiaries | | Attributable to | | Derivative Contracts | | Registrant Subsidiaries | | Attributable to | |
| | | with Credit | | Would Have Been | | RTO and ISO | | with Credit | | Would Have Been | | RTO and ISO | |
Company | Company | | Downgrade Triggers | | Required to Post | | Activities | | Downgrade Triggers | | Required to Post | | Activities | |
| | | (in thousands) | | (in thousands) | |
APCo | APCo | | $ | 7,600 | | $ | 9,459 | | $ | 9,261 | | | $ | 6,250 | | | $ | 14,845 | | | $ | 14,845 | |
CSPCo | CSPCo | | | 4,381 | | | 5,453 | | | 5,339 | | | | 3,578 | | | | 8,499 | | | | 8,499 | |
I&M | I&M | | | 4,570 | | | 5,688 | | | 5,569 | | | | 3,668 | | | | 8,713 | | | | 8,713 | |
OPCo | OPCo | | | 5,347 | | | 6,656 | | | 6,517 | | | | 4,292 | | | | 10,195 | | | | 10,195 | |
PSO | PSO | | | 10 | | | 1,809 | | | 1,694 | | | | - | | | | 1,930 | | | | 1,272 | |
SWEPCo | SWEPCo | | | 12 | | | 2,167 | | | 2,029 | | | | - | | | | 2,312 | | | | 1,524 | |
| | December 31, 2010 | |
| | Liabilities for | | Amount of Collateral the | | Amount | |
| | Derivative Contracts | | Registrant Subsidiaries | | Attributable to | |
| | with Credit | | Would Have Been | | RTO and ISO | |
Company | | Downgrade Triggers | | Required to Post | | Activities | |
| | (in thousands) | |
APCo | | | $ | 6,594 | | | $ | 12,607 | | | $ | 12,574 | |
CSPCo | | | | 3,801 | | | | 7,267 | | | | 7,248 | |
I&M | | | | 3,965 | | | | 7,581 | | | | 7,561 | |
OPCo | | | | 4,640 | | | | 8,871 | | | | 8,847 | |
PSO | | | | 16 | | | | 1,785 | | | | 1,385 | |
SWEPCo | | | | 19 | | | | 2,139 | | | | 1,659 | |
As of September 30,March 31, 2011 and December 31, 2010, the Registrant Subsidiaries were not required to post any cash collateral.
| | | December 31, 2009 |
| | | | | | | | | | |
| | | Liabilities for | | Amount of Collateral the | | Amount |
| | | Derivative Contracts | | Registrant Subsidiaries | | Attributable to |
| | | with Credit | | Would Have Been | | RTO and ISO |
Company | | Downgrade Triggers | | Required to Post | | Activities |
| | | (in thousands) |
APCo | | $ | 2,229 | | $ | 8,433 | | $ | 7,947 |
CSPCo | | | 1,129 | | | 4,272 | | | 4,026 |
I&M | | | 1,139 | | | 4,309 | | | 4,060 |
OPCo | | | 1,315 | | | 4,975 | | | 4,688 |
PSO | | | 689 | | | 2,772 | | | 2,083 |
SWEPCo | | | 819 | | | 3,297 | | | 2,477 |
As of December 31, 2009, the Registrant Subsidiaries were not required to post any collateral.
In addition, a majority of the Registrant Subsidiaries’ non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. Management does not anticipate a non-performance event under these provisions. The following tables representrepresent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount t histhis exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries’ contractual netting arrangements as of September 30, 2010March 31, 2011 and December 31, 2009:2010:
| | | September 30, 2010 | |
| | | | | | | | | | | | | March 31, 2011 |
| | | Liabilities for | | | | Additional | | | Liabilities for | | | | Additional |
| | | Contracts with Cross | | | | Settlement | | | Contracts with Cross | | | | Settlement |
| | | Default Provisions | | | | Liability if Cross | | | Default Provisions | | | | Liability if Cross |
| | | Prior to Contractual | | Amount of Cash | | Default Provision | | | Prior to Contractual | | Amount of Cash | | Default Provision |
Company | Company | | Netting Arrangements | | Collateral Posted | | is Triggered | Company | | Netting Arrangements | | Collateral Posted | | is Triggered |
| | | (in thousands) | | | (in thousands) |
APCo | APCo | | $ | 128,044 | | $ | 19,328 | | $ | 30,372 | APCo | | $ | 70,073 | | $ | 4,091 | | $ | 26,341 |
CSPCo | CSPCo | | | 73,111 | | | 11,142 | | | 16,807 | CSPCo | | | 40,116 | | | 2,342 | | | 15,080 |
I&M | I&M | | | 76,260 | | | 11,622 | | | 17,528 | I&M | | | 41,130 | | | 2,401 | | | 15,463 |
OPCo | OPCo | | | 89,264 | | | 13,600 | | | 20,540 | OPCo | | | 48,146 | | | 2,810 | | | 18,112 |
PSO | PSO | | | 117 | | | - | | | 40 | PSO | | | 52 | | | - | | | 28 |
SWEPCo | SWEPCo | | | 233 | | | - | | | 133 | SWEPCo | | | 65 | | | - | | | 37 |
| | | | | | | | | | | | | | | | | | | | |
| | | December 31, 2009 | | | December 31, 2010 |
| | | | | | | | | | | | | Liabilities for | | | | Additional |
| | | Liabilities for | | | | Additional | | | Contracts with Cross | | | | Settlement |
| | | Contracts with Cross | | | | Settlement | | | Default Provisions | | | | Liability if Cross |
| | | Default Provisions | | | | Liability if Cross | | | Prior to Contractual | | Amount of Cash | | Default Provision |
| | | Prior to Contractual | | Amount of Cash | | Default Provision | |
Company | Company | | Netting Arrangements | | Collateral Posted | | is Triggered | Company | | Netting Arrangements | | Collateral Posted | | is Triggered |
| | | (in thousands) | | | (in thousands) |
APCo | APCo | | $ | 154,924 | | $ | 3,115 | | $ | 33,186 | APCo | | $ | 76,810 | | $ | 6,637 | | $ | 23,748 |
CSPCo | CSPCo | | | 78,489 | | | 1,578 | | | 16,813 | CSPCo | | | 44,277 | | | 3,826 | | | 13,689 |
I&M | I&M | | | 79,158 | | | 1,592 | | | 16,955 | I&M | | | 46,188 | | | 3,991 | | | 14,280 |
OPCo | OPCo | | | 91,430 | | | 1,838 | | | 19,615 | OPCo | | | 54,066 | | | 4,670 | | | 16,731 |
PSO | PSO | | | 40 | | | - | | | 40 | PSO | | | 60 | | | - | | | 28 |
SWEPCo | SWEPCo | | | 139 | | | - | | | 93 | SWEPCo | | | 75 | | | - | | | 37 |
9.8. FAIR VALUE MEASUREMENTS
Fair Value Hierarchy and Valuation Techniques
The accounting guidance for “Fair Value Measurements and Disclosures” 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). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.
For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated.
Management typically obtains multiple broker quotes, which are non-binding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations and iflocations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Long-dated and illiquid complex or structured transactions and 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 as Level 3.
AEP utilizes its trustee’s external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s investment managers perform their own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts.
Assets in the nuclear trusts and Other Cash Deposits are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets. Fixed income securities do not trade on an exchange and do not have an official closing price. Pricing vendors calculate bond valuations using financial models and matrices. Fixed income securities are typically classified as Level 2 holdings because their valuation inputs are based on observable market data. Observable inputs used for valuing fixed income securities are benchmark yields, reported trades, broker/dealer quotes, issuer spreads, two-sided markets, benchmark securities, bids, offers, reference data and economic events. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equities. They are valued based on observable inputs primarily unadjusted quoted prices in active markets for identical assets.
Items classified as Level 2 are primarily investments in individual fixed income securities. These fixed income securities are valued using models with input data as follows:
| | Type of Fixed Income Security |
| | United States | | | | State and Local |
Type of Input | | Government | | Corporate Debt | | Government |
| | | | | | |
Benchmark Yields | | X | | X | | X |
Broker Quotes | | X | | X | | X |
Discount Margins | | X | | X | | |
Treasury Market Update | | X | | | | |
Base Spread | | X | | X | | X |
Corporate Actions | | | | X | | |
Ratings Agency Updates | | | | X | | X |
Prepayment Schedule and History | | | | | | X |
Yield Adjustments | | X | | | | |
Fair Value Measurements of Long-term Debt
The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of September 30, 2010March 31, 2011 and December 31, 20092010 are summarized in the following table:
| | September 30, 2010 | | December 31, 2009 | | March 31, 2011 | | December 31, 2010 | |
Company | | Book Value | | Fair Value | | Book Value | | Fair Value | | Book Value | | Fair Value | | Book Value | | Fair Value | |
| | (in thousands) | | (in thousands) | |
APCo | | $ | 3,560,959 | | $ | 4,075,531 | | $ | 3,477,306 | | $ | 3,699,373 | | | $ | 3,975,705 | | | $ | 4,247,353 | | | $ | 3,561,141 | | | $ | 3,878,557 | |
CSPCo | | | 1,588,753 | | 1,791,795 | | | 1,536,393 | | 1,616,857 | | | | 1,438,900 | | | | 1,547,615 | | | | 1,438,830 | | | | 1,571,219 | |
I&M | | | 2,118,911 | | 2,399,239 | | | 2,077,906 | | 2,192,854 | | | | 1,999,103 | | | | 2,143,355 | | | | 2,004,226 | | | | 2,169,520 | |
OPCo | | | 2,929,386 | | 3,249,304 | | | 3,242,505 | | 3,380,084 | | | | 2,614,651 | | | | 2,798,115 | | | | 2,729,522 | | | | 2,945,280 | |
PSO | | | 970,643 | | 1,095,500 | | | 968,121 | | 1,007,183 | | | | 1,019,375 | | | | 1,077,368 | | | | 971,186 | | | | 1,040,656 | |
SWEPCo | | | 1,769,457 | | 2,050,992 | | | 1,474,153 | | 1,554,165 | | | | 1,769,583 | | | | 1,909,046 | | | | 1,769,520 | | | | 1,931,516 | |
Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal
Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include:
· | Acceptable investments (rated investment grade or above when purchased). |
· | Maximum percentage invested in a specific type of investment. |
· | Prohibition of investment in obligations of AEP or its affiliates. |
· | Withdrawals permitted only for payment of decommissioning costs and trust expenses. |
· | Target asset allocation is 50% fixed income and 50% equity securities. |
I&M maintains trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives.
I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether the investor has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment, among other things, is based on whether the investor has the ability and intent to hold the investment to recover its value. Other-than-temporary impairments for investments in both debt a ndand equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and debt investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. The gains, losses or other-than-temporary impairments shown below didConsequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw de commissioningdecommissioning funds.
The following is a summary of nuclear trust fund investments at September 30, 2010March 31, 2011 and December 31, 2009:2010:
| | | September 30, 2010 | | December 31, 2009 | March 31, 2011 | | December 31, 2010 | |
| | | Estimated | | Gross | | Other-Than- | | Estimated | | Gross | | Other-Than- | Estimated | | Gross | | Other-Than- | | Estimated | | Gross | | Other-Than- | |
| | Fair | Unrealized | Temporary | Fair | Unrealized | Temporary | Fair | | Unrealized | | Temporary | | Fair | | Unrealized | | Temporary | |
| | Value | Gains | Impairments | Value | Gains | Impairments | Value | | Gains | | Impairments | | Value | | Gains | | Impairments | |
| | | (in thousands) | (in thousands) | |
Cash and Cash Equivalents | Cash and Cash Equivalents | | $ | 30,217 | | $ | - | | $ | - | | $ | 14,412 | | $ | - | | $ | - | | $ | 14,524 | | | $ | - | | | $ | - | | | $ | 20,039 | | | $ | - | | | $ | - | |
Fixed Income Securities: | Fixed Income Securities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| United States Government | | 489,026 | | 40,901 | | (1,036) | | 400,565 | | 12,708 | | (3,472) | |
| Corporate Debt | | 64,744 | | 5,039 | | (1,988) | | 57,291 | | 4,636 | | (2,177) | |
| State and Local Government | | | 307,660 | | | (6,991) | | | (527) | | | 368,930 | | | 7,924 | | | 991 | |
| Subtotal Fixed Income Securities | | 861,430 | | 38,949 | | (3,551) | | 826,786 | | 25,268 | | (4,658) | |
United States Government | | | | 472,913 | | | | 17,432 | | | | (1,236 | ) | | | 461,084 | | | | 22,582 | | | | (1,489 | ) |
Corporate Debt | | | | 54,836 | | | | 3,161 | | | | (1,499 | ) | | | 59,463 | | | | 3,716 | | | | (1,905 | ) |
State and Local Government | | | | 339,651 | | | | 1,663 | | | | 268 | | | | 340,786 | | | | (975 | ) | | | (340 | ) |
Subtotal Fixed Income Securities | | | | 867,400 | | | | 22,256 | | | | (2,467 | ) | | | 861,333 | | | | 25,323 | | | | (3,734 | ) |
Equity Securities - Domestic | Equity Securities - Domestic | | | 574,052 | | | 124,051 | | | (122,769) | | | 550,721 | | | 234,437 | | | (119,379) | | | 676,611 | | | | 226,445 | | | | (113,418 | ) | | | 633,855 | | | | 183,447 | | | | (122,889 | ) |
Spent Nuclear Fuel and | Spent Nuclear Fuel and | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Decommissioning Trusts | | $ | 1,465,699 | | $ | 163,000 | | $ | (126,320) | | $ | 1,391,919 | | $ | 259,705 | | $ | (124,037) | |
Decommissioning Trusts | | | $ | 1,558,535 | | | $ | 248,701 | | | $ | (115,885 | ) | | $ | 1,515,227 | | | $ | 208,770 | | | $ | (126,623 | ) |
The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2010March 31, 2011 and 2009:2010:
| | Three Months Ended | | Nine Months Ended | |
| | September 30, | | September 30, | Three Months Ended March 31, | |
| | 2010 | | 2009 | | 2010 | | 2009 | 2011 | | 2010 | |
| | (in thousands) | (in thousands) | |
Proceeds From Investment Sales | | $ | 495,221 | | $ | 112,900 | | $ | 1,087,484 | | $ | 523,927 | | $ | 287,761 | | | $ | 232,078 | |
Purchases of Investments | | 511,688 | | 129,239 | | 1,128,747 | | 571,167 | | | 305,945 | | | | 247,632 | |
Gross Realized Gains on Investment Sales | | 1,168 | | 1,137 | | 7,518 | | 10,490 | | | 5,013 | | | | 5,328 | |
Gross Realized Losses on Investment Sales | | 33 | | 196 | | 450 | | 1,004 | | | 5,247 | | | | 181 | |
The adjusted cost of debt securities was $823$845 million and $801$835 million as of September 30, 2010March 31, 2011 and December 31, 2009,2010, respectively. The adjusted cost of equity securities was $450 million and $451 million as of March 31, 2011 and December 31, 2010, respectively.
The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at September 30, 2010March 31, 2011 was as follows:
| Fair Value | | |
| of Debt | | Fair Value | |
| Securities | | | |
| (in thousands) | | (in thousands) | |
Within 1 year | | $ | 13,134 | | | $ | 77,765 | |
1 year – 5 years | | | 346,079 | | | | 271,161 | |
5 years – 10 years | | | 266,801 | | | | 268,243 | |
After 10 years | | | 235,416 | | | | 250,231 | |
Total | | $ | 861,430 | | | $ | 867,400 | |
Fair Value Measurements of Financial Assets and Liabilities
The following tables set 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, 2010March 31, 2011 and December 31, 2009.2010. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” 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. There have not been any significant changes in management’s v aluationvaluation techniques.
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |
March 31, 2011 | |
APCo | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (f) | | $ | 1,329 | | | $ | 279,128 | | | $ | 12,455 | | | $ | (217,825 | ) | | $ | 75,087 | |
Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | |
Commodity Hedges (a) | | | - | | | | 3,643 | | | | - | | | | (2,696 | ) | | | 947 | |
Dedesignated Risk Management Contracts (b) | | | - | | | | - | | | | - | | | | 3,155 | | | | 3,155 | |
Total Risk Management Assets | | $ | 1,329 | | | $ | 282,771 | | | $ | 12,455 | | | $ | (217,366 | ) | | $ | 79,189 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (f) | | $ | 1,301 | | | $ | 261,618 | | | $ | 6,983 | | | $ | (234,514 | ) | | $ | 35,388 | |
Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | |
Commodity Hedges (a) | | | - | | | | 3,393 | | | | - | | | | (2,696 | ) | | | 697 | |
Total Risk Management Liabilities | | $ | 1,301 | | | $ | 265,011 | | | $ | 6,983 | | | $ | (237,210 | ) | | $ | 36,085 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |
December 31, 2010 | |
APCo | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (f) | | $ | 1,686 | | | $ | 330,605 | | | $ | 13,791 | | | $ | (270,012 | ) | | $ | 76,070 | |
Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | |
Commodity Hedges (a) | | | - | | | | 2,591 | | | | - | | | | (2,258 | ) | | | 333 | |
Interest Rate/Foreign Currency Hedges | | | - | | | | 11,888 | | | | - | | | | - | | | | 11,888 | |
Dedesignated Risk Management Contracts (b) | | | - | | | | - | | | | - | | | | 3,371 | | | | 3,371 | |
Total Risk Management Assets | | $ | 1,686 | | | $ | 345,084 | | | $ | 13,791 | | | $ | (268,899 | ) | | $ | 91,662 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (f) | | $ | 1,653 | | | $ | 312,258 | | | $ | 8,660 | | | $ | (284,432 | ) | | $ | 38,139 | |
Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | |
Commodity Hedges (a) | | | - | | | | 2,985 | | | | - | | | | (2,258 | ) | | | 727 | |
Total Risk Management Liabilities | | $ | 1,653 | | | $ | 315,243 | | | $ | 8,660 | | | $ | (286,690 | ) | | $ | 38,866 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis | Assets and Liabilities Measured at Fair Value on a Recurring Basis | Assets and Liabilities Measured at Fair Value on a Recurring Basis | |
September 30, 2010 | |
APCo | | | | | | | | | | |
March 31, 2011 | | March 31, 2011 | |
CSPCo | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | Assets: | (in thousands) | | (in thousands) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | Risk Management Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (g) | $ | 2,786 | | $ | 489,714 | | $ | 27,711 | | $ | (412,038) | | $ | 108,173 | |
Risk Management Commodity Contracts (a) (f) | | | $ | 761 | | | $ | 161,143 | | | $ | 7,131 | | | $ | (126,002 | ) | | $ | 43,033 | |
Cash Flow Hedges: | Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | | 1,548 | | | - | | | (1,478) | | 70 | |
Commodity Hedges (a) | | | | - | | | | 2,005 | | | | - | | | | (1,543 | ) | | | 462 | |
Dedesignated Risk Management Contracts (b) | Dedesignated Risk Management Contracts (b) | | - | | | - | | | - | | | 4,822 | | | 4,822 | | | - | | | | - | | | | - | | | | 1,806 | | | | 1,806 | |
Total Risk Management Assets | Total Risk Management Assets | $ | 2,786 | | $ | 491,262 | | $ | 27,711 | | $ | (408,694) | | $ | 113,065 | | $ | 761 | | | $ | 163,148 | | | $ | 7,131 | | | $ | (125,739 | ) | | $ | 45,301 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Liabilities: | Liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (g) | $ | 2,725 | | $ | 478,028 | | $ | 11,146 | | $ | (452,592) | | $ | 39,307 | |
Risk Management Commodity Contracts (a) (f) | | | $ | 745 | | | $ | 151,121 | | | $ | 3,997 | | | $ | (135,556 | ) | | $ | 20,307 | |
Cash Flow Hedges: | Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | 4,845 | | | - | | | (1,478) | | 3,367 | |
| Interest Rate/Foreign Currency Hedges | | - | | 1,216 | | | - | | | - | | 1,216 | |
DETM Assignment (c) | | - | | | - | | | - | | | 632 | | | 632 | |
Commodity Hedges (a) | | | | - | | | | 1,942 | | | | - | | | | (1,543 | ) | | | 399 | |
Total Risk Management Liabilities | Total Risk Management Liabilities | $ | 2,725 | | $ | 484,089 | | $ | 11,146 | | $ | (453,438) | | $ | 44,522 | | $ | 745 | | | $ | 153,063 | | | $ | 3,997 | | | $ | (137,099 | ) | | $ | 20,706 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis | Assets and Liabilities Measured at Fair Value on a Recurring Basis | Assets and Liabilities Measured at Fair Value on a Recurring Basis | |
December 31, 2009 | |
APCo | | | | | | | | | | |
December 31, 2010 | | December 31, 2010 | |
CSPCo | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | Assets: | (in thousands) | | (in thousands) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other Cash Deposits (d) | $ | 421 | | $ | - | | $ | - | | $ | 51 | | $ | 472 | |
| | | | | | | | | | | | | | |
Risk Management Assets | Risk Management Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) | | 2,344 | | | 449,406 | | | 12,866 | | | (360,248) | | 104,368 | |
Risk Management Commodity Contracts (a) (f) | | | $ | 972 | | | $ | 185,699 | | | $ | 7,950 | | | $ | (150,930 | ) | | $ | 43,691 | |
Cash Flow Hedges: | Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | | 3,620 | | | - | | | (1,621) | | 1,999 | |
Commodity Hedges (a) | | | | - | | | | 1,531 | | | | - | | | | (1,302 | ) | | | 229 | |
Dedesignated Risk Management Contracts (b) | Dedesignated Risk Management Contracts (b) | | - | | | - | | | - | | | 8,730 | | | 8,730 | | | - | | | | - | | | | - | | | | 1,943 | | | | 1,943 | |
Total Risk Management Assets | Total Risk Management Assets | | 2,344 | | | 453,026 | | | 12,866 | | | (353,139) | | | 115,097 | | $ | 972 | | | $ | 187,230 | | | $ | 7,950 | | | $ | (150,289 | ) | | $ | 45,863 | |
| | | | | | | | | | | | | | | |
Total Assets | $ | 2,765 | | $ | 453,026 | | $ | 12,866 | | $ | (353,088) | | $ | 115,569 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Liabilities: | Liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) | $ | 2,648 | | $ | 422,063 | | $ | 3,438 | | $ | (388,265) | | $ | 39,884 | |
Risk Management Commodity Contracts (a) (f) | | | $ | 953 | | | $ | 175,078 | | | $ | 4,975 | | | $ | (159,235 | ) | | $ | 21,771 | |
Cash Flow Hedges: | Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | 5,163 | | | - | | | (1,621) | | 3,542 | |
DETM Assignment (c) | | - | | | - | | | - | | | 2,730 | | | 2,730 | |
Commodity Hedges (a) | | | | - | | | | 1,721 | | | | - | | | | (1,302 | ) | | | 419 | |
Total Risk Management Liabilities | Total Risk Management Liabilities | $ | 2,648 | | $ | 427,226 | | $ | 3,438 | | $ | (387,156) | | $ | 46,156 | | $ | 953 | | | $ | 176,799 | | | $ | 4,975 | | | $ | (160,537 | ) | | $ | 22,190 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |
March 31, 2011 | |
I&M | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (f) | | $ | 780 | | | $ | 188,676 | | | $ | 7,309 | | | $ | (140,757 | ) | | $ | 56,008 | |
Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | |
Commodity Hedges (a) | | | - | | | | 2,081 | | | | - | | | | (1,582 | ) | | | 499 | |
Dedesignated Risk Management Contracts (b) | | | - | | | | - | | | | - | | | | 1,852 | | | | 1,852 | |
Total Risk Management Assets | | | 780 | | | | 190,757 | | | | 7,309 | | | | (140,487 | ) | | | 58,359 | |
| | | | | | | | | | | | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | | | | | | | | | | | |
Cash and Cash Equivalents (d) | | | - | | | | 4,994 | | | | - | | | | 9,530 | | | | 14,524 | |
Fixed Income Securities: | | | | | | | | | | | | | | | | | | | | |
United States Government | | | - | | | | 472,913 | | | | - | | | | - | | | | 472,913 | |
Corporate Debt | | | - | | | | 54,836 | | | | - | | | | - | | | | 54,836 | |
State and Local Government | | | - | | | | 339,651 | | | | - | | | | - | | | | 339,651 | |
Subtotal Fixed Income Securities | | | - | | | | 867,400 | | | | - | | | | - | | | | 867,400 | |
Equity Securities - Domestic (e) | | | 676,611 | | | | - | | | | - | | | | - | | | | 676,611 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | | | 676,611 | | | | 872,394 | | | | - | | | | 9,530 | | | | 1,558,535 | |
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 677,391 | | | $ | 1,063,151 | | | $ | 7,309 | | | $ | (130,957 | ) | | $ | 1,616,894 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (f) | | $ | 763 | | | $ | 166,936 | | | $ | 4,100 | | | $ | (150,553 | ) | | $ | 21,246 | |
Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | |
Commodity Hedges (a) | | | - | | | | 1,991 | | | | - | | | | (1,582 | ) | | | 409 | |
Total Risk Management Liabilities | | $ | 763 | | | $ | 168,927 | | | $ | 4,100 | | | $ | (152,135 | ) | | $ | 21,655 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis |
September 30, 2010 |
CSPCo | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | (in thousands) |
| | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (g) | $ | 1,606 | | $ | 280,931 | | $ | 15,972 | | $ | (236,273) | | $ | 62,236 |
Cash Flow Hedges: | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | | 876 | | | - | | | (844) | | | 32 |
Dedesignated Risk Management Contracts (b) | | - | | | - | | | - | | | 2,780 | | | 2,780 |
Total Risk Management Assets | $ | 1,606 | | $ | 281,807 | | $ | 15,972 | | $ | (234,337) | | $ | 65,048 |
| | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (g) | $ | 1,571 | | $ | 274,233 | | $ | 6,425 | | $ | (259,644) | | $ | 22,585 |
Cash Flow Hedges: | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | | 2,784 | | | - | | | (844) | | | 1,940 |
DETM Assignment (c) | | - | | | - | | | - | | | 364 | | | 364 |
Total Risk Management Liabilities | $ | 1,571 | | $ | 277,017 | | $ | 6,425 | | $ | (260,124) | | $ | 24,889 |
| Assets and Liabilities Measured at Fair Value on a Recurring Basis | |
| December 31, 2009 | |
CSPCo | | | | | | | | | | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis | | Assets and Liabilities Measured at Fair Value on a Recurring Basis | |
December 31, 2010 | | December 31, 2010 | |
I&M | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | Assets: | (in thousands) | | (in thousands) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other Cash Deposits (d) | $ | 16,129 | | $ | - | | $ | - | | $ | 21 | | $ | 16,150 | |
| | | | | | | | | | | | | | |
Risk Management Assets | Risk Management Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) | | 1,188 | | | 227,150 | | | 6,518 | | | (182,038) | | 52,818 | |
Risk Management Commodity Contracts (a) (f) | | | $ | 1,014 | | | $ | 209,031 | | | $ | 8,295 | | | $ | (161,531 | ) | | $ | 56,809 | |
Cash Flow Hedges: | Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | | 1,805 | | | - | | | (821) | | 984 | |
Commodity Hedges (a) | | | | - | | | | 1,533 | | | | - | | | | (1,358 | ) | | | 175 | |
Dedesignated Risk Management Contracts (b) | Dedesignated Risk Management Contracts (b) | | - | | | - | | | - | | | 4,423 | | | 4,423 | | | - | | | | - | | | | - | | | | 2,027 | | | | 2,027 | |
Total Risk Management Assets | Total Risk Management Assets | | 1,188 | | | 228,955 | | | 6,518 | | | (178,436) | | | 58,225 | | | 1,014 | | | | 210,564 | | | | 8,295 | | | | (160,862 | ) | | | 59,011 | |
| | | | | | | | | | | | | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | | | | | | | | | | | | |
Cash and Cash Equivalents (d) | | | | - | | | | 7,898 | | | | - | | | | 12,141 | | | | 20,039 | |
Fixed Income Securities: | | | | | | | | | | | | | | | | | | | | | |
United States Government | | | | - | | | | 461,084 | | | | - | | | | - | | | | 461,084 | |
Corporate Debt | | | | - | | | | 59,463 | | | | - | | | | - | | | | 59,463 | |
State and Local Government | | | | - | | | | 340,786 | | | | - | | | | - | | | | 340,786 | |
Subtotal Fixed Income Securities | | | | - | | | | 861,333 | | | | - | | | | - | | | | 861,333 | |
Equity Securities - Domestic (e) | | | | 633,855 | | | | - | | | | - | | | | - | | | | 633,855 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | | | | 633,855 | | | | 869,231 | | | | - | | | | 12,141 | | | | 1,515,227 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Assets | Total Assets | $ | 17,317 | | $ | 228,955 | | $ | 6,518 | | $ | (178,415) | | $ | 74,375 | | $ | 634,869 | | | $ | 1,079,795 | | | $ | 8,295 | | | $ | (148,721 | ) | | $ | 1,574,238 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Liabilities: | Liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) | $ | 1,342 | | $ | 213,330 | | $ | 1,742 | | $ | (196,226) | | $ | 20,188 | |
Risk Management Commodity Contracts (a) (f) | | | $ | 994 | | | $ | 186,898 | | | $ | 5,187 | | | $ | (170,201 | ) | | $ | 22,878 | |
Cash Flow Hedges: | Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | 2,615 | | | - | | | (821) | | 1,794 | |
DETM Assignment (c) | | - | | | - | | | - | | | 1,383 | | | 1,383 | |
Commodity Hedges (a) | | | | - | | | | 1,795 | | | | - | | | | (1,358 | ) | | | 437 | |
Total Risk Management Liabilities | Total Risk Management Liabilities | $ | 1,342 | | $ | 215,945 | | $ | 1,742 | | $ | (195,664) | | $ | 23,365 | | $ | 994 | | | $ | 188,693 | | | $ | 5,187 | | | $ | (171,559 | ) | | $ | 23,315 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis | Assets and Liabilities Measured at Fair Value on a Recurring Basis | Assets and Liabilities Measured at Fair Value on a Recurring Basis | |
September 30, 2010 | |
I&M | | | | | | | | | | |
March 31, 2011 | | March 31, 2011 | |
OPCo | | | | | | | | | | | | | | | | |
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | Assets: | (in thousands) | | (in thousands) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other Cash Deposits (c) | | | $ | 26 | | | $ | - | | | $ | - | | | $ | 22 | | | $ | 48 | |
| | | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | Risk Management Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (g) | $ | 1,676 | | $ | 301,988 | | $ | 16,655 | | $ | (242,039) | | $ | 78,280 | |
Risk Management Commodity Contracts (a) (f) | | | | 912 | | | | 272,395 | | | | 8,554 | | | | (227,554 | ) | | | 54,307 | |
Cash Flow Hedges: | Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | | 919 | | | - | | | (882) | | 37 | |
Commodity Hedges (a) | | | | - | | | | 2,538 | | | | - | | | | (1,851 | ) | | | 687 | |
Dedesignated Risk Management Contracts (b) | Dedesignated Risk Management Contracts (b) | | - | | | - | | | - | | | 2,900 | | | 2,900 | | | - | | | | - | | | | - | | | | 2,166 | | | | 2,166 | |
Total Risk Management Assets | Total Risk Management Assets | | 1,676 | | | 302,907 | | | 16,655 | | | (240,021) | | | 81,217 | | | 912 | | | | 274,933 | | | | 8,554 | | | | (227,239 | ) | | | 57,160 | |
| | | | | | | | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | | | | | |
Cash and Cash Equivalents (e) | | - | | | 20,776 | | | - | | | 9,441 | | 30,217 | |
Fixed Income Securities: | | | | | | | | | | | | | | |
| United States Government | | - | | | 489,026 | | | - | | | - | | 489,026 | |
| Corporate Debt | | - | | | 64,744 | | | - | | | - | | 64,744 | |
| State and Local Government | | - | | | 307,660 | | | - | | | - | | | 307,660 | |
| | Subtotal Fixed Income Securities | | - | | | 861,430 | | | - | | | - | | 861,430 | |
Equity Securities - Domestic (f) | | 574,052 | | | - | | | - | | | - | | | 574,052 | |
Total Spent Nuclear Fuel and Decommissioning Trusts | | 574,052 | | | 882,206 | | | - | | | 9,441 | | | 1,465,699 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Assets | Total Assets | $ | 575,728 | | $ | 1,185,113 | | $ | 16,655 | | $ | (230,580) | | $ | 1,546,916 | | $ | 938 | | | $ | 274,933 | | | $ | 8,554 | | | $ | (227,217 | ) | | $ | 57,208 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Liabilities: | Liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (g) | $ | 1,639 | | $ | 281,426 | | $ | 6,697 | | $ | (266,397) | | $ | 23,365 | |
Risk Management Commodity Contracts (a) (f) | | | $ | 893 | | | $ | 260,433 | | | $ | 4,795 | | | $ | (239,020 | ) | | $ | 27,101 | |
Cash Flow Hedges: | Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | 2,905 | | | - | | | (882) | | 2,023 | |
DETM Assignment (c) | | - | | | - | | | - | | | 380 | | | 380 | |
Commodity Hedges (a) | | | | - | | | | 2,330 | | | | - | | | | (1,851 | ) | | | 479 | |
Total Risk Management Liabilities | Total Risk Management Liabilities | $ | 1,639 | | $ | 284,331 | | $ | 6,697 | | $ | (266,899) | | $ | 25,768 | | $ | 893 | | | $ | 262,763 | | | $ | 4,795 | | | $ | (240,871 | ) | | $ | 27,580 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |
December 31, 2010 | |
OPCo | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Other Cash Deposits (c) | | $ | 26 | | | $ | - | | | $ | - | | | $ | - | | | $ | 26 | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (f) | | | 1,186 | | | | 314,560 | | | | 9,709 | | | | (269,216 | ) | | | 56,239 | |
Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | |
Commodity Hedges (a) | | | - | | | | 1,764 | | | | - | | | | (1,590 | ) | | | 174 | |
Dedesignated Risk Management Contracts (b) | | | - | | | | - | | | | - | | | | 2,372 | | | | 2,372 | |
Total Risk Management Assets | | | 1,186 | | | | 316,324 | | | | 9,709 | | | | (268,434 | ) | | | 58,785 | |
| | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 1,212 | | | $ | 316,324 | | | $ | 9,709 | | | $ | (268,434 | ) | | $ | 58,811 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (f) | | $ | 1,163 | | | $ | 302,299 | | | $ | 6,101 | | | $ | (279,505 | ) | | $ | 30,058 | |
Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | |
Commodity Hedges (a) | | | - | | | | 2,101 | | | | - | | | | (1,590 | ) | | | 511 | |
Total Risk Management Liabilities | | $ | 1,163 | | | $ | 304,400 | | | $ | 6,101 | | | $ | (281,095 | ) | | $ | 30,569 | |
| | Assets and Liabilities Measured at Fair Value on a Recurring Basis |
| | December 31, 2009 |
I&M | | | | | | | | | |
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | (in thousands) |
| | | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) | $ | 1,198 | | $ | 231,777 | | $ | 6,571 | | $ | (181,446) | | $ | 58,100 |
Cash Flow Hedges: | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | | 1,839 | | | - | | | (828) | | | 1,011 |
Dedesignated Risk Management Contracts (b) | | - | | | - | | | - | | | 4,461 | | | 4,461 |
Total Risk Management Assets | | 1,198 | | | 233,616 | | | 6,571 | | | (177,813) | | | 63,572 |
| | | | | | | | | | | | | | | | |
Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | | | | | |
Cash and Cash Equivalents (e) | | - | | | 3,562 | | | - | | | 10,850 | | | 14,412 |
Fixed Income Securities: | | | | | | | | | | | | | | |
| United States Government | | - | | | 400,565 | | | - | | | - | | | 400,565 |
| Corporate Debt | | - | | | 57,291 | | | - | | | - | | | 57,291 |
| State and Local Government | | - | | | 368,930 | | | - | | | - | | | 368,930 |
| | Subtotal Fixed Income Securities | | - | | | 826,786 | | | - | | | - | | | 826,786 |
Equity Securities - Domestic (f) | | 550,721 | | | - | | | - | | | - | | | 550,721 |
Total Spent Nuclear Fuel and Decommissioning Trusts | | 550,721 | | | 830,348 | | | - | | | 10,850 | | | 1,391,919 |
| | | | | | | | | | | | | | | | |
Total Assets | $ | 551,919 | | $ | 1,063,964 | | $ | 6,571 | | $ | (166,963) | | $ | 1,455,491 |
| | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) | $ | 1,353 | | $ | 213,242 | | $ | 1,755 | | $ | (195,732) | | $ | 20,618 |
Cash Flow Hedges: | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | | 2,637 | | | - | | | (828) | | | 1,809 |
DETM Assignment (c) | | - | | | - | | | - | | | 1,395 | | | 1,395 |
Total Risk Management Liabilities | $ | 1,353 | | $ | 215,879 | | $ | 1,755 | | $ | (195,165) | | $ | 23,822 |
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |
March 31, 2011 | |
PSO | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (f) | | $ | 1 | | | $ | 15,783 | | | $ | - | | | $ | (15,129 | ) | | $ | 655 | |
Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | |
Commodity Hedges | | | - | | | | 376 | | | | - | | | | - | | | | 376 | |
Total Risk Management Assets | | $ | 1 | | | $ | 16,159 | | | $ | - | | | $ | (15,129 | ) | | $ | 1,031 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (f) | | $ | 1 | | | $ | 16,516 | | | $ | - | | | $ | (15,131 | ) | | $ | 1,386 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |
December 31, 2010 | |
PSO | | | | | | | | | | | | | | | |
| | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | | (in thousands) | |
| | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (f) | | $ | - | | | $ | 21,119 | | | $ | 1 | | | $ | (20,335 | ) | | $ | 785 | |
Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | |
Commodity Hedges | | | - | | | | 134 | | | | - | | | | - | | | | 134 | |
Interest Rate/Foreign Currency Hedges | | | - | | | | 13,558 | | | | - | | | | - | | | | 13,558 | |
Total Risk Management Assets | | $ | - | | | $ | 34,811 | | | $ | 1 | | | $ | (20,335 | ) | | $ | 14,477 | |
| | | | | | | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (f) | | $ | - | | | $ | 21,498 | | | $ | - | | | $ | (20,379 | ) | | $ | 1,119 | |
| Assets and Liabilities Measured at Fair Value on a Recurring Basis | |
| September 30, 2010 | |
OPCo | | | | | | | | | | | | | | | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis | | Assets and Liabilities Measured at Fair Value on a Recurring Basis | |
March 31, 2011 | | March 31, 2011 | |
SWEPCo | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | Assets: | (in thousands) | | (in thousands) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Other Cash Deposits (d) | $ | 26 | | $ | - | | $ | - | | $ | - | | $ | 26 | |
| | | | | | | | | | | | |
Risk Management Assets | Risk Management Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (g) | | 1,961 | | | 373,224 | | | 19,540 | | | (316,496) | | 78,229 | |
Risk Management Commodity Contracts (a) (f) | | | $ | 1 | | | $ | 28,968 | | | $ | - | | | $ | (27,927 | ) | | $ | 1,042 | |
Cash Flow Hedges: | Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | | 1,092 | | | - | | | (1,042) | | 50 | |
Dedesignated Risk Management Contracts (b) | | - | | | - | | | - | | | 3,393 | | | 3,393 | |
Commodity Hedges | | | | - | | | | 347 | | | | - | | | | - | | | | 347 | |
Interest Rate/Foreign Currency Hedges | | | | - | | | | 9 | | | | - | | | | - | | | | 9 | |
Total Risk Management Assets | Total Risk Management Assets | | 1,961 | | | 374,316 | | | 19,540 | | | (314,145) | | | 81,672 | | $ | 1 | | | $ | 29,324 | | | $ | - | | | $ | (27,927 | ) | | $ | 1,398 | |
| | | | | | | | | | | | | | | |
Total Assets | $ | 1,987 | | $ | 374,316 | | $ | 19,540 | | $ | (314,145) | | $ | 81,698 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Liabilities: | Liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (g) | $ | 1,917 | | $ | 366,812 | | $ | 7,883 | | $ | (345,156) | | $ | 31,456 | |
Risk Management Commodity Contracts (a) (f) | | | $ | 1 | | | $ | 30,508 | | | $ | - | | | $ | (27,930 | ) | | $ | 2,579 | |
Cash Flow Hedges: | Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | 3,412 | | | - | | | (1,042) | | 2,370 | |
DETM Assignment (c) | | - | | | - | | | - | | | 445 | | | 445 | |
Commodity Hedges | | | | - | | | | 1 | | | | - | | | | - | | | | 1 | |
Total Risk Management Liabilities | Total Risk Management Liabilities | $ | 1,917 | | $ | 370,224 | | $ | 7,883 | | $ | (345,753) | | $ | 34,271 | | $ | 1 | | | $ | 30,509 | | | $ | - | | | $ | (27,930 | ) | | $ | 2,580 | |
| Assets and Liabilities Measured at Fair Value on a Recurring Basis |
| December 31, 2009 |
OPCo | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | (in thousands) |
| | | | | | | | | | | | | | | |
Other Cash Deposits (d) | $ | 1,075 | | $ | - | | $ | - | | $ | 24 | | $ | 1,099 |
| | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) | | 1,383 | | | 332,904 | | | 7,644 | | | (270,272) | | | 71,659 |
Cash Flow Hedges: | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | | 2,199 | | | - | | | (957) | | | 1,242 |
Dedesignated Risk Management Contracts (b) | | - | | | - | | | - | | | 5,150 | | | 5,150 |
Total Risk Management Assets | | 1,383 | | | 335,103 | | | 7,644 | | | (266,079) | | | 78,051 |
| | | | | | | | | | | | | | | |
Total Assets | $ | 2,458 | | $ | 335,103 | | $ | 7,644 | | $ | (266,055) | | $ | 79,150 |
| | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) | $ | 1,562 | | $ | 317,114 | | $ | 2,075 | | $ | (287,549) | | $ | 33,202 |
Cash Flow Hedges: | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | | 3,045 | | | - | | | (957) | | | 2,088 |
DETM Assignment (c) | | - | | | - | | | - | | | 1,611 | | | 1,611 |
Total Risk Management Liabilities | $ | 1,562 | | $ | 320,159 | | $ | 2,075 | | $ | (286,895) | | $ | 36,901 |
| Assets and Liabilities Measured at Fair Value on a Recurring Basis |
| September 30, 2010 |
PSO | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | (in thousands) |
| | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (g) | $ | 9 | | $ | 9,098 | | $ | 11 | | $ | (5,638) | | $ | 3,480 |
Cash Flow Hedges: | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | | 69 | | | - | | | (48) | | | 21 |
Total Risk Management Assets | $ | 9 | | $ | 9,167 | | $ | 11 | | $ | (5,686) | | $ | 3,501 |
| | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (g) | $ | 8 | | $ | 6,066 | | $ | 9 | | $ | (5,693) | | $ | 390 |
Cash Flow Hedges: | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | | 69 | | | - | | | (48) | | | 21 |
DETM Assignment (c) | | - | | | - | | | - | | | 16 | | | 16 |
Total Risk Management Liabilities | $ | 8 | | $ | 6,135 | | $ | 9 | | $ | (5,725) | | $ | 427 |
| Assets and Liabilities Measured at Fair Value on a Recurring Basis |
| December 31, 2009 |
PSO | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | (in thousands) |
| | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) | $ | - | | $ | 17,494 | | $ | 14 | | $ | (15,260) | | $ | 2,248 |
Cash Flow Hedges: | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | | 179 | | | - | | | (1) | | | 178 |
Total Risk Management Assets | $ | - | | $ | 17,673 | | $ | 14 | | $ | (15,261) | | $ | 2,426 |
| | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) | $ | - | | $ | 17,865 | | $ | 12 | | $ | (15,454) | | $ | 2,423 |
Cash Flow Hedges: | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | | 301 | | | - | | | (1) | | | 300 |
Total Risk Management Liabilities | $ | - | | $ | 18,166 | | $ | 12 | | $ | (15,455) | | $ | 2,723 |
Assets and Liabilities Measured at Fair Value on a Recurring Basis |
September 30, 2010 |
SWEPCo | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
Assets: | (in thousands) |
| | | | | | | | | | | | | | | |
Risk Management Assets | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (g) | $ | 11 | | $ | 15,793 | | $ | 21 | | $ | (13,416) | | $ | 2,409 |
Cash Flow Hedges: | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | | 51 | | | - | | | (32) | | | 19 |
| Interest Rate/Foreign Currency Hedges (a) | | - | | | 8 | | | - | | | - | | | 8 |
Total Risk Management Assets | $ | 11 | | $ | 15,852 | | $ | 21 | | $ | (13,448) | | $ | 2,436 |
| | | | | | | | | | | | | | | |
Liabilities: | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | |
Risk Management Liabilities | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) (g) | $ | 10 | | $ | 14,153 | | $ | 19 | | $ | (13,504) | | $ | 678 |
Cash Flow Hedges: | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | | 43 | | | - | | | (32) | | | 11 |
| Interest Rate/Foreign Currency Hedges (a) | | - | | | 87 | | | - | | | - | | | 87 |
DETM Assignment (c) | | - | | | - | | | - | | | 19 | | | 19 |
Total Risk Management Liabilities | $ | 10 | | $ | 14,283 | | $ | 19 | | $ | (13,517) | | $ | 795 |
| Assets and Liabilities Measured at Fair Value on a Recurring Basis | |
| December 31, 2009 | |
Assets and Liabilities Measured at Fair Value on a Recurring Basis | | Assets and Liabilities Measured at Fair Value on a Recurring Basis | |
December 31, 2010 | | December 31, 2010 | |
SWEPCo | SWEPCo | | | | | | | | | | | | | | | | | | | | | | | | |
| | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | |
Assets: | Assets: | (in thousands) | | (in thousands) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Assets | Risk Management Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) | $ | - | | $ | 26,945 | | $ | 22 | | $ | (24,007) | | $ | 2,960 | |
Risk Management Commodity Contracts (a) (f) | | | $ | - | | | $ | 36,632 | | | $ | 2 | | | $ | (35,115 | ) | | $ | 1,519 | |
Cash Flow Hedges: | Cash Flow Hedges: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | | 216 | | | - | | | (43) | | | 173 | |
Commodity Hedges | | | | - | | | | 123 | | | | - | | | | - | | | | 123 | |
Interest Rate/Foreign Currency Hedges | | | | - | | | | 5 | | | | - | | | | - | | | | 5 | |
Total Risk Management Assets | Total Risk Management Assets | $ | - | | $ | 27,161 | | $ | 22 | | $ | (24,050) | | $ | 3,133 | | $ | - | | | $ | 36,760 | | | $ | 2 | | | $ | (35,115 | ) | | $ | 1,647 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Liabilities: | Liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Liabilities | Risk Management Liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Risk Management Commodity Contracts (a) | $ | - | | $ | 25,312 | | $ | 19 | | $ | (24,312) | | $ | 1,019 | |
Cash Flow Hedges: | | | | | | | | | | | | | |
| Commodity Hedges (a) | | - | | | 89 | | | - | | | (43) | | | 46 | |
Total Risk Management Liabilities | $ | - | | $ | 25,401 | | $ | 19 | | $ | (24,355) | | $ | 1,065 | |
Risk Management Commodity Contracts (a) (f) | | | $ | - | | | $ | 39,592 | | | $ | - | | | $ | (35,187 | ) | | $ | 4,405 | |
(a) | Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” |
(b) | Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for “Derivatives and Hedging.” At the time of the normal election, the MTM value was frozen and no longer fair valued. This MTM value will be amortized into revenues over the remaining life of the contracts. |
(c) | See “Natural Gas Contracts with DETM” section of Note 15 in the 2009 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)(d) | Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 2 amounts primarily represent investments in money market funds. |
(f)(e) | Amounts represent publicly traded equity securities and equity-based mutual funds. |
(g)(f) | Substantially comprised of power contracts for APCo, CSPCo, I&M and OPCo and coal contracts for PSO and SWEPCo. |
There have beenwere no transfers between Level 1 and Level 2 during the ninethree months ended September 30,March 31, 2011 and 2010.
The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:
Three Months Ended September 30, 2010 | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo | |
Three Months Ended March 31, 2011 | | Three Months Ended March 31, 2011 | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) | | | (in thousands) |
Balance as of June 30, 2010 | | $ | 10,874 | | $ | 6,153 | | $ | 6,209 | | $ | 7,069 | | $ | (2) | | $ | (2) | |
Balance as of December 31, 2010 | | Balance as of December 31, 2010 | | $ | 5,131 | | $ | 2,975 | | $ | 3,108 | | $ | 3,608 | | $ | 1 | | $ | 2 |
Realized Gain (Loss) Included in Net Income | Realized Gain (Loss) Included in Net Income | | | | | | | | | | | | | Realized Gain (Loss) Included in Net Income | | | | | | | | | | | | |
| (or Changes in Net Assets) (a) (b) | | (1,680) | | (845) | | (850) | | (981) | | 2 | | 2 | (or Changes in Net Assets) (a) (b) | | (586) | | (335) | | (344) | | (401) | | - | | - |
Unrealized Gain (Loss) Included in Net | Unrealized Gain (Loss) Included in Net | | | | | | | | | | | | | Unrealized Gain (Loss) Included in Net | | | | | | | | | | | | |
| Income (or Changes in Net Assets) Relating | | | | | | | | | | | | | Income (or Changes in Net Assets) Relating | | | | | | | | | | | | |
| to Assets Still Held at the Reporting Date (a) | | | - | | 5,941 | | - | | 9,258 | | - | | - | to Assets Still Held at the Reporting Date (a) | | | - | | 2,159 | | - | | 2,524 | | - | | - |
Realized and Unrealized Gains (Losses) | Realized and Unrealized Gains (Losses) | | | | | | | | | | | | | Realized and Unrealized Gains (Losses) | | | | | | | | | | | | |
| Included in Other Comprehensive Income | | - | | - | | - | | - | | - | | - | Included in Other Comprehensive Income | | - | | - | | - | | - | | - | | - |
Purchases, Issuances and Settlements (c) | Purchases, Issuances and Settlements (c) | | 195 | | 118 | | 133 | | 157 | | 2 | | 3 | Purchases, Issuances and Settlements (c) | | (1,333) | | (763) | | (783) | | (916) | | - | | - |
Transfers into Level 3 (d) (h)(f) | Transfers into Level 3 (d) (h)(f) | | 380 | | 215 | | 217 | | 247 | | - | | - | Transfers into Level 3 (d) (h)(f) | | 95 | | 55 | | 57 | | 67 | | - | | - |
Transfers out of Level 3 (e) (h)(f) | Transfers out of Level 3 (e) (h)(f) | | (890) | | (503) | | (508) | | (579) | | (1) | | (2) | Transfers out of Level 3 (e) (h)(f) | | (2,654) | | (1,531) | | (1,596) | | (1,868) | | - | | - |
Changes in Fair Value Allocated to Regulated | Changes in Fair Value Allocated to Regulated | | | | | | | | | | | | | Changes in Fair Value Allocated to Regulated | | | | | | | | | | | | |
| Jurisdictions (g) | | | 7,686 | | | (1,532) | | | 4,757 | | | (3,514) | | | 1 | | | 1 | Jurisdictions (g) | | | 4,819 | | | 574 | | | 2,767 | | | 745 | | | (1) | | | (2) |
Balance as of September 30, 2010 | | $ | 16,565 | | $ | 9,547 | | $ | 9,958 | | $ | 11,657 | | $ | 2 | | $ | 2 | |
Balance as of March 31, 2011 | | Balance as of March 31, 2011 | | $ | 5,472 | | $ | 3,134 | | $ | 3,209 | | $ | 3,759 | | $ | - | | $ | - |
Nine Months Ended September 30, 2010 | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in thousands) |
Balance as of December 31, 2009 | | $ | 9,428 | | $ | 4,776 | | $ | 4,816 | | $ | 5,569 | | $ | 2 | | $ | 3 |
Realized Gain (Loss) Included in Net Income | | | | | | | | | | | | | | | | | | |
| (or Changes in Net Assets) (a) (b) | | | 1,269 | | | 713 | | | 721 | | | 825 | | | 1 | | | 3 |
Unrealized Gain (Loss) Included in Net | | | | | | | | | | | | | | | | | | |
| Income (or Changes in Net Assets) Relating | | | | | | | | | | | | | | | | | | |
| to Assets Still Held at the Reporting Date (a) | | | - | | | 10,670 | | | - | | | 14,651 | | | - | | | - |
Realized and Unrealized Gains (Losses) | | | | | | | | | | | | | | | | | | |
| Included in Other Comprehensive Income | | | - | | | - | | | - | | | - | | | - | | | - |
Purchases, Issuances and Settlements (c) | | | (5,463) | | | (3,059) | | | (3,100) | | | (3,565) | | | (1) | | | (2) |
Transfers into Level 3 (d) (h) | | | 986 | | | 530 | | | 528 | | | 615 | | | - | | | - |
Transfers out of Level 3 (e) (h) | | | (2,088) | | | (1,195) | | | (1,199) | | | (1,376) | | | - | | | - |
Changes in Fair Value Allocated to Regulated | | | | | | | | | | | | | | | | | | |
| Jurisdictions (g) | | | 12,433 | | | (2,888) | | | 8,192 | | | (5,062) | | | - | | | (2) |
Balance as of September 30, 2010 | | $ | 16,565 | | $ | 9,547 | | $ | 9,958 | | $ | 11,657 | | $ | 2 | | $ | 2 |
Three Months Ended September 30, 2009 | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in thousands) |
Balance as of June 30, 2009 | | $ | 13,900 | | $ | 7,372 | | $ | 7,135 | | $ | 9,410 | | $ | 12 | | $ | 15 |
Realized (Gain) Loss Included in Net Income | | | | | | | | | | | | | | | | | | |
| (or Changes in Net Assets) (a) | | | (2,762) | | | (1,465) | | | (1,418) | | | (2,087) | | | (11) | | | (13) |
Unrealized Gain (Loss) Included in Net | | | | | | | | | | | | | | | | | | |
| Income (or Changes in Net Assets) Relating | | | | | | | | | | | | | | | | | | |
| to Assets Still Held at the Reporting Date (a) | | | - | | | 347 | | | - | | | (185) | | | - | | | - |
Realized and Unrealized Gains (Losses) | | | | | | | | | | | | | | | | | | |
| Included in Other Comprehensive Income | | | - | | | - | | | - | | | - | | | - | | | - |
Purchases, Issuances and Settlements | | | - | | | - | | | - | | | - | | | - | | | - |
Transfers in and/or out of Level 3 (f) | | | 2,322 | | | 1,231 | | | 1,192 | | | 1,525 | | | - | | | - |
Changes in Fair Value Allocated to Regulated | | | | | | | | | | | | | | | | | | |
| Jurisdictions (g) | | | 10,188 | | | 5,047 | | | 5,176 | | | 5,723 | | | 4 | | | 4 |
Balance as of September 30, 2009 | | $ | 23,648 | | $ | 12,532 | | $ | 12,085 | | $ | 14,386 | | $ | 5 | | $ | 6 |
Nine Months Ended September 30, 2009 | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in thousands) |
Balance as of December 31, 2008 | | $ | 8,009 | | $ | 4,497 | | $ | 4,352 | | $ | 5,563 | | $ | (2) | | $ | (3) |
Realized (Gain) Loss Included in Net Income | | | | | | | | | | | | | | | | | | |
| (or Changes in Net Assets) (a) | | | (6,448) | | | (3,621) | | | (3,504) | | | (4,473) | | | 3 | | | 5 |
Unrealized Gain (Loss) Included in Net | | | | | | | | | | | | | | | | | | |
| Income (or Changes in Net Assets) Relating | | | | | | | | | | | | | | | | | | |
| to Assets Still Held at the Reporting Date (a) | | | - | | | 6,069 | | | - | | | 6,906 | | | - | | | - |
Realized and Unrealized Gains (Losses) | | | | | | | | | | | | | | | | | | |
| Included in Other Comprehensive Income | | | - | | | - | | | - | | | - | | | - | | | - |
Purchases, Issuances and Settlements | | | - | | | - | | | - | | | - | | | - | | | - |
Transfers in and/or out of Level 3 (f) | | | (328) | | | (184) | | | (178) | | | (228) | | | - | | | - |
Changes in Fair Value Allocated to Regulated | | | | | | | | | | | | | | | | | | |
| Jurisdictions (g) | | | 22,415 | | | 5,771 | | | 11,415 | | | 6,618 | | | 4 | | | 4 |
Balance as of September 30, 2009 | | $ | 23,648 | | $ | 12,532 | | $ | 12,085 | | $ | 14,386 | | $ | 5 | | $ | 6 |
Three Months Ended March 31, 2010 | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in thousands) |
Balance as of December 31, 2009 | | $ | 9,428 | | $ | 4,776 | | $ | 4,816 | | $ | 5,569 | | $ | 2 | | $ | 3 |
Realized Gain (Loss) Included in Net Income | | | | | | | | | | | | | | | | | | |
| (or Changes in Net Assets) (a) (b) | | | 8,947 | | | 5,056 | | | 5,099 | | | 5,818 | | | - | | | - |
Unrealized Gain (Loss) Included in Net | | | | | | | | | | | | | | | | | | |
| Income (or Changes in Net Assets) Relating | | | | | | | | | | | | | | | | | | |
| to Assets Still Held at the Reporting Date (a) | | | - | | | 6,122 | | | - | | | 6,987 | | | - | | | - |
Realized and Unrealized Gains (Losses) | | | | | | | | | | | | | | | | | | |
| Included in Other Comprehensive Income | | | - | | | - | | | - | | | - | | | - | | | - |
Purchases, Issuances and Settlements (c) | | | (10,221) | | | (5,743) | | | (5,792) | | | (6,612) | | | - | | | - |
Transfers into Level 3 (d) (f) | | | 439 | | | 222 | | | 224 | | | 259 | | | - | | | - |
Transfers out of Level 3 (e) (f) | | | 269 | | | 137 | | | 138 | | | 159 | | | - | | | - |
Changes in Fair Value Allocated to Regulated | | | | | | | | | | | | | | | | | | |
| Jurisdictions (g) | | | 9,825 | | | - | | | 6,177 | | | - | | | - | | | 1 |
Balance as of March 31, 2010 | | $ | 18,687 | | $ | 10,570 | | $ | 10,662 | | $ | 12,180 | | $ | 2 | | $ | 4 |
(a) | Included in revenues on the Condensed Statements of Income. |
(b) | Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. |
(c) | Represents the settlement of risk management commodity contracts for the reporting period. |
(d) | Represents existing assets or liabilities that were previously categorized as Level 2. |
(e) | Represents existing assets or liabilities that were previously categorized as Level 3. |
(f) | Represents existing assets or liabilitiesTransfers are recognized based on their value at the beginning of the reporting period 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.transfer occurred. |
(g) | 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. |
(h) | Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. |
10.9. INCOME TAXES
The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. 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 tax expense. The tax benefit 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 company in the consolidated group.
The Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2001. The Registrant Subsidiaries have completed the exam for the years 2001 through 2006 and have issues that are being pursued at the appeals level. TheIn April 2011, the IRS’s examination of the years 2007 and 2008 are currently under examination.was concluded with a settlement of all outstanding issues. The settlement will not have a material impact on net income, cash flows or financial condition. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal 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 believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not 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, I&M, OPCo, PSO and SWEPCo
The Patient Protection and Affordable Care Act and the related Health Care and Education Reconciliation Act (Health Care Acts) were enacted in March 2010. The Health Care Acts amend tax rules so that the portion of employer health care costs that are reimbursed by the Medicare Part D prescription drug subsidy will no longer be deductible by the employer for federal income tax purposes effective for years beginning after December 31, 2012. Because of the loss of the future tax deduction, a reduction in the deferred tax asset related to the nondeductible OPEB liabilities accrued to date was recorded by the Registrant Subsidiaries in March 2010. This reduction did not materially affect the Registrant Subsidiaries' cash flows or financial condition. For the ninethree months ended September 30,March 31, 2010, the Registrant Subsidiaries reflected a decrease in deferred tax assets, which was partially offset by recording net tax regulatory assets in jurisdictions with regulated operations, resulting in a decrease in net income as follows:
| | Net Reduction | | Tax | | | |
| | to Deferred | | Regulatory | | Decrease in | |
Company | | Tax Assets | | Assets, Net | | Net Income | |
| | (in thousands) | |
APCo | | $ | 9,397 | | $ | 8,831 | | $ | 566 | |
CSPCo | | | 4,386 | | | 2,970 | | | 1,416 | |
I&M | | | 7,212 | | | 6,528 | | | 684 | |
OPCo | | | 8,385 | | | 4,020 | | | 4,365 | |
PSO | | | 3,172 | | | 3,172 | | | - | |
SWEPCo | | | 3,412 | | | 3,412 | | | - | |
The Small Business Jobs Act (the Act) was enacted in September 2010. Included in this actthe Act was a one-year extension of the 50% bonus depreciation provision. The Tax Relief, Unemployment Insurance Reauthorization and the Job Creation Act of 2010 extended the life of research and development, employment and several energy tax credits originally scheduled to expire at the end of 2010. In addition, the Act extended the time for claiming bonus depreciation and increased the deduction to 100% for part of 2010 and 2011. The enacted provisionprovisions will not have a material impact on the Registrant Subsidiaries’ net income or financial condition but will have a material favorable impact on cash flows.
condition.
11.10. FINANCING ACTIVITIES
Long-term Debt
Long-term debt and other securities issued, retired and principal payments made during the first ninethree months of 2010 were:2011 are shown in the tables below.
| | | | Principal | | Interest | | Due | | | | Principal | | Interest | | Due |
Company | | Type of Debt | | Amount | | Rate | | Date | | Type of Debt | | Amount | | Rate | | Date |
| | | | (in thousands) | | (%) | | | |
Issuances: | | | | | | | | | | | | | (in thousands) | | (%) | | |
APCo | | Senior Unsecured Notes | | $ | 300,000 | | 3.40 | | 2015 | | Senior Unsecured Notes | | $ | 350,000 | | 4.60 | | 2021 |
APCo | | Pollution Control Bonds | | 17,500 | | 4.625 | | 2021 | | Pollution Control Bonds | | 65,350 | | 2.00 | | 2012 |
APCo | | Pollution Control Bonds | | 50,000 | | 5.375 | | 2038 | | Pollution Control Bonds | | 75,000 | (a) | Variable | | 2036 |
CSPCo | | Floating Rate Notes | | 150,000 | | Variable | | 2012 | |
APCo | | | Pollution Control Bonds | | 54,375 | (a) | Variable | | 2042 |
APCo | | | Pollution Control Bonds | | 50,275 | (a) | Variable | | 2036 |
APCo | | | Pollution Control Bonds | | 50,000 | (a) | Variable | | 2042 |
I&M | | | Pollution Control Bonds | | 52,000 | (a) | Variable | | 2021 |
I&M | | Notes Payable | | 84,500 | | 4.00 | | 2014 | | Pollution Control Bonds | | 25,000 | (a) | Variable | | 2019 |
OPCo | | Pollution Control Bonds | | 79,450 | | 3.25 | | 2014 | | Pollution Control Bonds | | 50,000 | (a) | Variable | | 2014 |
OPCo | | Pollution Control Bonds | | 86,000 | | 3.125 | | 2015 | |
OPCo | | Pollution Control Bonds | | 39,130 | | 2.875 | | 2014 | |
SWEPCo | | Senior Unsecured Notes | | 350,000 | | 6.20 | | 2040 | |
SWEPCo | | Pollution Control Bonds | | 53,500 | | 3.25 | | 2015 | |
PSO | | Notes Payable | | 1,750 | | 3.00 | | 2025 | | Senior Unsecured Notes | | 250,000 | | 4.40 | | 2021 |
| | | | | Principal | | Interest | | Due |
Company | | Type of Debt | | Amount Paid | | Rate | | Date |
| | | | | (in thousands) | | (%) | | |
Retirements and | | | | | | | | | |
| Principal Payments: | | | | | | | | | |
APCo | | Land Note | | $ | 14 | | 13.718 | | 2026 |
APCo | | Notes Payable - Affiliated | | | 100,000 | | 4.708 | | 2010 |
APCo | | Senior Unsecured Notes | | | 150,000 | | 4.40 | | 2010 |
APCo | | Pollution Control Bonds | | | 50,000 | | 7.125 | | 2010 |
CSPCo | | Notes Payable - Affiliated | | | 100,000 | | 4.64 | | 2010 |
I&M | | Notes Payable - Affiliated | | | 25,000 | | 5.375 | | 2010 |
I&M | | Notes Payable | | | 19,200 | | 5.44 | | 2013 |
OPCo | | Senior Unsecured Notes | | | 400,000 | | Variable | | 2010 |
OPCo | | Pollution Control Bonds | | | 79,450 | | 7.125 | | 2010 |
OPCo | | Pollution Control Bonds | | | 19,565 | | 5.625 | | 2022 |
OPCo | | Pollution Control Bonds | | | 19,565 | | 5.625 | | 2023 |
SWEPCo | | Notes Payable - Affiliated | | | 50,000 | | 4.45 | | 2010 |
SWEPCo | | Pollution Control Bonds | | | 53,500 | | Variable | | 2019 |
(a) | These pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year – Nonaffiliated on the balance sheets. |
| | | | Principal | | Interest | | Due |
Company | | Type of Debt | | Amount Paid | | Rate | | Date |
Retirements and | | | | (in thousands) | | (%) | | |
Principal Payments: | | | | | | | | | |
APCo | | Pollution Control Bonds | | $ | 75,000 | | Variable | | 2036 |
APCo | | Pollution Control Bonds | | | 54,375 | | Variable | | 2042 |
APCo | | Pollution Control Bonds | | | 50,000 | | Variable | | 2042 |
APCo | | Pollution Control Bonds | | | 50,275 | | Variable | | 2036 |
APCo | | Land Note | | | 5 | | 13.718 | | 2026 |
I&M | | Pollution Control Bonds | | | 52,000 | | Variable | | 2021 |
I&M | | Pollution Control Bonds | | | 25,000 | | Variable | | 2019 |
I&M | | Notes Payable | | | 5,354 | | Variable | | 2015 |
OPCo | | Pollution Control Bonds | | | 65,000 | | Variable | | 2036 |
OPCo | | Pollution Control Bonds | | | 50,000 | | Variable | | 2014 |
OPCo | | Pollution Control Bonds | | | 50,000 | | Variable | | 2014 |
PSO | | Senior Unsecured Notes | | | 200,000 | | 6.00 | | 2032 |
In October 2010, I&MApril 2011, APCo retired $150$250 million of 6%5.55% Senior Unsecured Notes due in 2032.
In November 2010, OPCo retired $200 million of 5.3% Senior Unsecured Notes due in 2010.2011.
OnIn April 2011, I&M retired $30 million of Notes Payable related to DCC Fuel.
As of March 31, 2011, trustees held, on behalf of OPCo, trustees held $303$418 million of its reacquired auction-rate tax-exempt long-term debt as of September 30, 2010.Pollution Control Bonds.
Dividend Restrictions
The Registrant Subsidiaries pay dividends to the Parent provided funds are legally available. Various financing arrangements, charter provisions and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to the Parent in the form of dividends.
Federal Power Act
The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. As applicable, the Registrant Subsidiaries understand “capital account” to mean the par value of the common stock multiplied by the number of shares outstanding.
Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generating plants. Because of their respective ownership of such plants, this reserve applies to APCo, I&M and OPCo.
None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings.
Charter and Leverage Restrictions
Provisions within the articles or certificates of incorporation of the Registrant Subsidiaries relating to preferred stock or shares restrict the payment of cash dividends on common and preferred stock or shares. Pursuant to the credit agreement leverage restrictions, the Registrant Subsidiaries must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%.
At September 30, 2010,March 31, 2011, approximately $111$175 million of theAPCo’s retained earnings, of APCo, $148$76 million of theCSPCo’s retained earnings, of CSPCo, $29$101 million of theSWEPCo’s retained earnings of I&M, $49 million of the retained earnings of OPCo, $100 million of the retained earnings of SWEPCo and none of theI&M’s, OPCo’s and PSO’s retained earnings of PSO have restrictions related to the payment of dividends to Parent.
Utility 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 Utility 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, 2010March 31, 2011 and December 31, 20092010 is 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, 2010March 31, 2011 are described in the following table:
| | | | | | | | | | | | Loans | | |
| | | Maximum | | Maximum | | Average | | Average | | (Borrowings) | | Authorized |
| | | Borrowings | | Loans | | Borrowings | | Loans | | to/from Utility | | Short-term |
| | | from Utility | | to Utility | | from Utility | | to Utility | | Money Pool as of | | Borrowing |
| Company | | Money Pool | | Money Pool | | Money Pool | | Money Pool | | September 30, 2010 | | Limit |
| | | (in thousands) |
| APCo | | $ | 438,039 | | $ | - | | $ | 275,422 | | $ | - | | $ | (55,113) | | $ | 600,000 |
| CSPCo | | | 134,592 | | | 201,486 | | | 32,368 | | | 71,571 | | | 182,225 | | | 350,000 |
| I&M | | | - | | | 223,111 | | | - | | | 110,696 | | | 192,779 | | | 500,000 |
| OPCo | | | - | | | 618,559 | | | - | | | 256,426 | | | 290,714 | | | 600,000 |
| PSO | | | 107,320 | | | 74,751 | | | 50,927 | | | 41,836 | | | (23,024) | | | 300,000 |
| SWEPCo | | | 78,616 | | | 274,958 | | | 39,458 | | | 218,555 | | | 213,689 | | | 350,000 |
| | Maximum | | Maximum | | Average | | Average | | Loans | | Authorized |
| | Borrowings | | Loans | | Borrowings | | Loans | | to Utility | | Short-term |
| | from Utility | | to Utility | | from Utility | | to Utility | | Money Pool as of | | Borrowing |
Company | | Money Pool | | Money Pool | | Money Pool | | Money Pool | | March 31, 2011 | | Limit |
| | (in thousands) |
APCo | | | $ | 195,945 | | | $ | 393,811 | | | $ | 102,608 | | | $ | 155,100 | | | $ | 383,537 | | | $ | 600,000 |
CSPCo | | | | 17,256 | | | | 107,040 | | | | 10,098 | | | | 61,695 | | | | 63,706 | | | | 350,000 |
I&M | | | | 52,098 | | | | 89,276 | | | | 15,525 | | | | 36,839 | | | | 56,813 | | | | 500,000 |
OPCo | | | | 51,169 | | | | 237,196 | | | | 28,199 | | | | 131,959 | | | | 82,684 | | | | 600,000 |
PSO | | | | 96,034 | | | | 255,611 | | | | 49,522 | | | | 144,127 | | | | 3,093 | | | | 300,000 |
SWEPCo | | | | 20,596 | | | | 105,184 | | | | 8,647 | | | | 48,281 | | | | 9,367 | | | | 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, |
| | 2010 | | 2009 | | 2011 | | 2010 |
Maximum Interest Rate | | | 0.55 | % | | | 2.28 | % | | | 0.56 | % | | | 0.34 | % |
Minimum Interest Rate | | | 0.09 | % | | | 0.27 | % | | | 0.06 | % | | | 0.09 | % |
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the ninethree months ended September 30,March 31, 2011 and 2010 and 2009 are summarized for all Registrant Subsidiaries in the following table:
| | Average Interest Rate for Funds | | Average Interest Rate for Funds | | Average Interest Rate | | Average Interest Rate |
| | Borrowed from | | Loaned to | | for Funds Borrowed | | for Funds Loaned |
| | the Utility Money Pool for the | | the Utility Money Pool for the | | from Utility Money Pool for | | to Utility Money Pool for |
| | Nine Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended March 31, | | Three Months Ended March 31, |
Company | | 2010 | | 2009 | 2010 | | 2009 | | 2011 | | 2010 | | 2011 | | 2010 |
| | | | | | | | | | | | | | | | | | | | | | | |
APCo | | 0.25 | % | | 1.14 | % | | - | % | | - | % | | | 0.38 | % | | | 0.16 | % | | | 0.17 | % | | | - | % |
CSPCo | | 0.18 | % | | 1.13 | % | | 0.27 | % | | 0.57 | % | | | 0.52 | % | | | 0.18 | % | | | 0.28 | % | | | 0.14 | % |
I&M | | - | % | | 1.46 | % | | 0.24 | % | | 0.49 | % | | | 0.48 | % | | | - | % | | | 0.25 | % | | | 0.16 | % |
OPCo | | - | % | | 1.21 | % | | 0.20 | % | | 0.38 | % | | | 0.41 | % | | | - | % | | | 0.26 | % | | | 0.16 | % |
PSO | | 0.29 | % | | 2.01 | % | | 0.16 | % | | 1.04 | % | | | 0.47 | % | | | 0.16 | % | | | 0.19 | % | | | 0.16 | % |
SWEPCo | | 0.19 | % | | 1.66 | % | | 0.27 | % | | 0.77 | % | | | 0.36 | % | | | 0.19 | % | | | 0.32 | % | | | 0.13 | % |
Short-term Debt
The Registrant Subsidiaries’ outstanding short-term debt was as follows:
| | | | | | September 30, 2010 | | December 31, 2009 |
| | | | | | Outstanding | | Interest | | Outstanding | | Interest |
| Company | | Type of Debt | Amount | Rate (b) | | Amount | Rate (b) |
| | | | | | (in thousands) | | | | | (in thousands) | | | |
| SWEPCo | | Line of Credit – Sabine (a) | | $ | 3,170 | | 2.20 | % | | $ | 6,890 | | 2.06 | % |
| | | | | | | | | | | | | | | | |
| (a) | Sabine Mining Company is a consolidated variable interest entity. |
| (b) | Weighted average rate. |
Short-term Debt | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
The Registrant Subsidiaries’ outstanding short-term debt was as follows: |
| | | | | | | | | | | | | | | | |
| | | | | | March 31, 2011 | | December 31, 2010 |
| | | | | | Outstanding | | Interest | | Outstanding | | Interest |
| Company | | Type of Debt | Amount | Rate (b) | | Amount | Rate (b) |
| | | | | | (in thousands) | | | | | (in thousands) | | | |
| SWEPCo | | Line of Credit – Sabine (a) | | $ | - | | - | % | | $ | 6,217 | | 2.15 | % |
| | | | | | | | | | | | | | | | |
| (a) | Sabine Mining Company is a consolidated variable interest entity. |
| (b) | Weighted average rate. |
Credit Facilities
AEP has credit facilities totaling $3 billion to support the commercial paper program. The facilities are structured as two $1.5 billion credit facilities, ofunder which $750 millionup to $1.35 billion may be issued under one credit facility as letters of credit. In June 2010, AEP terminated one of the $1.5 billion facilities that was scheduled to mature in March 2011 and replaced it with a new $1.5 billion credit facility which matures in 2013 and allows for the issuance of up to $600 million as letters of credit. As of September 30, 2010,March 31, 2011, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $300$150 thousand for I&M and $4 million for SWEPCo.
In June 2010,March 2011, the Registrant Subsidiaries and certain other companies in the AEP System reduced the $627terminated a $478 million credit agreement that was scheduled to $478 million. Under the facility, letters of credit may be issued. As of September 30, 2010, $477 million of letters of credit were issuedmature in April 2011 and was used to support variable rate Pollution Control Bonds. In March 2011, certain variable rate Pollution Control Bonds were remarketed and supported by bilateral letters of credit for $361 million while others were reacquired and are being held in trust. As of March 31, 2011, $472 million of variable rate Pollution Control Bonds were remarketed or reacquired as follows:
| | | March 31, 2011 | |
| | | | | | Reacquired and | | Bilateral Letters | |
Company | | Amount | | | Remarketed | | Held in Trust | | of Credit Issued | |
| | (in thousands) | | | (in thousands) | |
APCo | | | $ | 232,292 | | | | $ | 229,650 | | | $ | - | | | $ | 232,293 | |
I&M | | | | 77,886 | | | | | 77,000 | | | | - | | | | 77,886 | |
OPCo | | | | 166,899 | | | | | 50,000 | | | | 115,000 | | | | 50,575 | |
Sale of Receivables – AEP Credit
Under a sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’sSubsidiary's receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ income statements. The Registrant Subsidiaries manage and service their customer accounts receivable sold.
In July 2010, AEP Credit renewed its receivables securitization agreement. The agreement provides a commitment of $750 million from bank conduits to purchase receivables. A commitment of $375 million expires in July 2011 and the remaining commitment of $375 million expires in July 2013.
The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of September 30, 2010March 31, 2011 and December 31, 20092010 was as follows:
| | September 30, | | | December 31, | | | March 31, | | | December 31, | |
Company | | 2010 | | | 2009 | | | 2011 | | | 2010 | |
| | (in thousands) | | | (in thousands) | |
APCo | | $ | 142,747 | | | $ | 143,938 | | | $ | 135,454 | | | $ | 145,515 | |
CSPCo | | | 196,949 | | | | 169,095 | | | | 169,436 | | | | 175,997 | |
I&M | | | 138,134 | | | | 130,193 | | | | 129,304 | | | | 123,366 | |
OPCo | | | 168,306 | | | | 160,977 | | | | 183,904 | | | | 168,701 | |
PSO | | | 161,179 | | | | 73,518 | | | | 104,740 | | | | 121,679 | |
SWEPCo | | | 169,235 | | | | 117,297 | | | | 116,594 | | | | 135,092 | |
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:
| | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended March 31, | |
Company | Company | | 2010 | | 2009 | | 2010 | | 2009 | | 2011 | | | 2010 | |
| | | (in thousands) | | (in thousands) | |
APCo | APCo | | $ | 2,949 | | $ | 1,186 | | $ | 6,725 | | $ | 3,711 | | $ | 2,575 | | | $ | 1,881 | |
CSPCo | CSPCo | | | 3,300 | | 2,956 | | 8,990 | | | 8,481 | | | 2,332 | | | | 2,908 | |
I&M | I&M | | | 1,832 | | 1,617 | | 5,276 | | 4,507 | | | 1,627 | | | | 1,787 | |
OPCo | OPCo | | | 2,345 | | 2,340 | | 7,494 | | 6,351 | | | 1,703 | | | | 2,700 | |
PSO | PSO | | 1,537 | | 1,738 | | 4,287 | | 5,397 | | | 1,234 | | | | 1,384 | |
SWEPCo | SWEPCo | | 1,441 | | 1,747 | | 4,574 | | 4,569 | | | 1,100 | | | | 1,671 | |
The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were:
| | | | | | | | | | |
| | | Three Months Ended September 30, | | Nine Months Ended September 30, | | Three Months Ended March 31, | |
Company | Company | | 2010 | | 2009 | | 2010 | | 2009 | | 2011 | | | 2010 | |
| | | (in thousands) | | (in thousands) | |
APCo | APCo | | $ | 338,446 | | $ | 298,997 | | $ | 1,097,276 | | $ | 923,408 | | $ | 366,209 | | | $ | 441,711 | |
CSPCo | CSPCo | | | 521,030 | | 442,079 | | 1,368,343 | | | 1,243,325 | | | 406,646 | | | | 424,685 | |
I&M | I&M | | | 348,039 | | 319,932 | | 984,631 | | 908,007 | | | 351,021 | | | | 339,208 | |
OPCo | OPCo | | | 473,773 | | 394,335 | | 1,325,613 | | 1,184,744 | | | 504,392 | | | | 441,510 | |
PSO | PSO | | 398,177 | | 265,622 | | 924,707 | | 812,264 | | | 268,569 | | | | 214,647 | |
SWEPCo | SWEPCo | | 430,270 | | 373,805 | | 1,087,515 | | 1,009,124 | | | 314,124 | | | | 318,959 | |
12.11. COST REDUCTION INITIATIVES
In April 2010, management began initiatives to decrease both labor and non-labor expenses with a goal of achieving significant reductions in operation and maintenance expenses. A total of 2,461 positions were eliminated across the AEP System as a result of process improvements, streamlined organizational designs and other efficiencies. Most of the affected employees terminated employment May 31, 2010. The severance program providesprovided two weeks of base pay for every year of service along with other severance benefits.
Management recorded a charge to Other Operation expense in the second quarter of 2010 primarily related to the headcount reduction initiatives. The total amount incurred in 2010 by Registrant Subsidiary was as follows:
| | | Expense | | Incurred for | | | | | | | Remaining |
| | | Allocation from | | Registrant | | | | | | | Balance at |
| | | AEPSC | | Subsidiaries | | Settled | | Adjustments | | September 30, 2010 |
| | | (in thousands) |
| APCo | | $ | 20,526 | | $ | 36,399 | | $ | 48,431 | | $ | (3,621) | | $ | 4,873 |
| CSPCo | | | 11,048 | | | 21,244 | | | 28,542 | | | (557) | | | 3,193 |
| I&M | | | 12,051 | | | 32,985 | | | 39,192 | | | (2,135) | | | 3,709 |
| OPCo | | | 19,427 | | | 33,681 | | | 50,923 | | | 2,175 | | | 4,360 |
| PSO | | | 10,681 | | | 13,324 | | | 20,908 | | | (651) | | | 2,446 |
| SWEPCo | | | 12,588 | | | 17,074 | | | 26,430 | | | (522) | | | 2,710 |
Company | | Total Cost Incurred | |
| | (in thousands) | |
APCo | | $ | 56,925 | |
CSPCo | | | 32,292 | |
I&M | | | 45,036 | |
OPCo | | | 53,108 | |
PSO | | | 24,005 | |
SWEPCo | | | 29,662 | |
These costs relaterelated primarily to severance benefits. TheyManagement does not expect additional costs to be incurred related to this initiative.
The Registrant Subsidiaries’ cost reduction activity for the three months ended March 31, 2011 is described in the following table:
| | Balance at | | | | | | | | | | | | Balance at | |
Company | | December 31, 2010 | | | Incurred | | | Settled | | | Adjustments | | | March 31, 2011 | |
| | (in thousands) | |
APCo | | $ | 3,726 | | | $ | - | | | $ | (1,946 | ) | | $ | (154 | ) | | $ | 1,626 | |
CSPCo | | | 1,454 | | | | - | | | | (1,219 | ) | | | (13 | ) | | | 222 | |
I&M | | | 2,198 | | | | - | | | | (1,421 | ) | | | (98 | ) | | | 679 | |
OPCo | | | 2,919 | | | | - | | | | (1,772 | ) | | | (91 | ) | | | 1,056 | |
PSO | | | 1,526 | | | | - | | | | (965 | ) | | | (48 | ) | | | 513 | |
SWEPCo | | | 1,753 | | | | - | | | | (1,089 | ) | | | (45 | ) | | | 619 | |
The remaining accruals are included primarily in Other Operation on the income statement and Other Current Liabilities on the balance sheet.Condensed Consolidated Balance Sheets.
COMBINED MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT SUBSIDIARIES
The following is a combined presentation of certain components of the 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)(a) Management’s Financial Discussion and Analysis, (ii)(b) financial statements, (iii)(c) footnotes and (iv)(d) the schedules of each individual registrant. The combinedCombined Management’s Discussion and Analysis of Registrant Subsidiaries section of the 20092010 Annual Report should also be read in conjunction with this report.
EXECUTIVE OVERVIEW
Economic Conditions
The Registrant Subsidiaries’ retail margins increased primarily due to successful rate proceedings in Indiana, Michigan, Ohio, Oklahoma, and Virginia and higher residential and commercial demand for electricity as a result of favorable weather. In comparison to the recessionary lows of 2009, industrialWest Virginia. Industrial sales increased 6%7% in the thirdfirst quarter and 5% during the first nine months of 20102011 for the AEP System. During 2009, theThe Registrant Subsidiaries’ operations were impacted by difficult economic conditions especially theirSubsidiaries, except PSO, had increased industrial sales. In 2011, industrial sales reflecting customers’ curtailments or closures of facilities. In 2009, CSPCo’sfor CSPCo and OPCo’sOPCo increased primarily due to increased production by their largest customer, Ormet, a major industrial customer, currently operating at a reduced load of approximately 330 MW, (Ormetwhich had operated at an approximate 500 MW loa d in 2008), announced that it will continue operations at this reduced level. In February 2009, Century Aluminum, a major industrial customer (325 MW load) of APCo, announcedlevels during the curtailment of operations at its Ravenswood, WV facility.
Capital Expenditures
In October 2010, management announced capital expenditures budgets by Registrant Subsidiaries for 2011 as follows:
| | Budgeted | |
| | Construction | |
Company | | Expenditures | |
| | (in millions) | |
APCo | | | $ | 466 | |
CSPCo | | | | 178 | |
I&M | | | | 307 | |
OPCo | | | | 271 | |
PSO | | | | 171 | |
SWEPCo | | | | 457 | |
earlier economic slowdown.
ENVIRONMENTAL ISSUES
The Registrant Subsidiaries are implementing a substantial capital investment program and incurring additional operational costs to comply with new environmental control requirements. The Registrant Subsidiaries will need to make additional investments and operational changes in response to existing and anticipated requirements such as CAA requirements to reduce emissions of SO2, NOx, PM and hazardous air pollutants from fossil fuel-fired power plants, and new proposals governing the beneficial use and disposal of coal combustion products.products and proposed clean water rules.
The Registrant Subsidiaries are engaged in litigation about environmental issues, have been notified of potential responsibility for the clean-up of contaminated sites and incur costs for disposal of SNF and future decommissioning of I&M’s nuclear units. Management is also involved in development of possible future requirements including the items discussed below and reductions of CO2 emissions to address concerns about global climate change. See a complete discussion of these matters in the “Environmental Matters”Issues” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” in the 20092010 Annual Report. Management will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulated jurisdictions. The Registrant Subsidiaries should be able to recover these expenditures through market prices in deregulated jurisdictions. If not, the costs of environmental compliance could adversely affect future net income, cash flows and possibly financial condition.
Update to Environmental Controls Impact on the Generating Fleet
The rules and proposed environmental controls discussed in the next several sections will have a material impact on the generating units in the AEP System. Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. In the first quarter of 2011, management revised cost estimates for complying with these rules. For the Registrant Subsidiaries, management’s current ranges of estimates of environmental investments to comply with these proposed requirements are listed below:
| | 2012 to 2020 | |
| | Estimated Environmental Investment | |
Company | | Low | | High | |
| | (in millions) | |
APCo | | | $ | 1,063 | | | $ | 1,906 | |
CSPCo | | | | 402 | | | | 569 | |
I&M | | | | 616 | | | | 1,459 | |
OPCo | | | | 1,250 | | | | 2,368 | |
PSO | | | | 27 | | | | 939 | |
SWEPCo | | | | 952 | | | | 1,327 | |
The projected environmental investments above include the replacement of a portion of the coal generation MWs for APCo.
The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in the final rules. The cost estimates for each Registrant Subsidiary will also change based on: (a) the states’ implementation of these regulatory programs, including the potential for state implementation plans or federal implementation plans that impose standards more stringent than the proposed rules, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of the pollution control technologies installed on the units, (d) changes in costs for new pollution controls, (e) new generating technology developments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) other factors.
Clean Air Act Transport Rule (Transport Rule)
In July 2010, the Federal EPA issued a proposed rule to replace the Clean Air Interstate Rule (CAIR) that would impose new and more stringent requirements to control SO2 and NOx emissions from fossil fuel-fired electric generating units in 31 states and the District of Columbia. Each state covered by the Transport Rule is assigned an allowance budget for SO2 and/or NOx. Limited interstate trading is allowed on a sub-regional basis and intrastate trading is allowed among generating units. PSO’s and SWEPCo& #8217;sSWEPCo’s western states (Texas, Arkansas and Oklahoma) would be subject to only the seasonal NOx program, with new limits that are proposed to take effect in 2012. The remainder of the states in which the AEP System operates would be subject to seasonal and annual NOx programs and an annual SO2 emissions reduction program that takes effect in two phases. The first phase becomes effective in 2012 and requires approximately 1one million tons per year more SO2 emission reductions across the region than would have been required under CAIR. The second phase takes effect in 2014 and reduces SO2 emissions by an additional 800,000 tons per year. The SO2 and NOx programs rely on newly-created allowances rather than relying on the CAIR NOx allowances or the Title IV Acid Rain Program allowances used in the CAIR rule.CAIR. The time frames for and stringency of the additional emission reductions, coupled with the lack of robust interstate trading and the elimination of historic allowance banks, pose significant concerns for the AEP System and its electric utility customers, as these featuresrequirements could accelerate unit retirements, increase capital requirements, constrain operations, decrease reliability and unfavorably impact financial condition if the increased costs are suspended during the early development stages not recovered in rates or market prices. CommentsThe Federal EPA requested comments on a scheme based exclusively on intrastate trading of allowances or a scheme that establishes unit-by-unit emission rates. Either of these options would provide less flexibility and exacerbate the proposed rule were due on October 1, 2010. The AEP System’s comments pointed ou t the inaccuracies of somenegative impact of the assumptions used by the Federal EPA, the flawed nature of its modeling analysis and unreasonable time frame for implementing the rule. Management believes that the Federal EPA made erroneous assumptions about the existence and/or capabilities of current control equipment at certain of the AEP System’s units, used timeframes for installation of new controls that are inconsistent with recent experience and made questionable assumptions regarding the ability to switch fuel supplies at existing units. A notice of additional information was issued and comments on that package were accepted until October 15, 2010. The proposal indicates that the requirements are expected to be finalized in June 2011 and become effective January 1, 2012.
Mercury and Other Hazardous Air Pollutants (HAPs) Regulation
The Federal EPA issued the Clean Air Mercury Rule (CAMR) in 2005, setting mercury emission standards for new coal-fired power plants and requiring all states to issue new state implementation plans including mercury requirements for existing coal-fired power plants. The CAMR was vacated and remanded to the Federal EPA by the D.C. Circuit Court of Appeals in 2008. The Federal EPA issued an information collection request to owners and operators of existing power plants in 2010 to collect information to support the development of a maximum achievable control technology (MACT) standard for mercury and other hazardous air pollutant emissions under the CAA. Under the terms of a consent decree,In response, the Federal EPA is required to issue final MACT standards forhas been developing a rule addressing a broad range of hazardous air pollutants from coal and oil-fired power plants by November 2011. 0;plants. The Federal EPA Administrator signed a proposed HAPs rule in March 2011, but the rule has substantial discretionnot yet been published in determining howthe Federal Register. The rule establishes unit-specific emission rates for mercury, PM (as a surrogate for particles of nonmercury metal) and hydrochloric acid (as a surrogate for acid gases) for units burning coal and oil, on a site-wide 30-day rolling average basis. In addition, the rule proposes work practice standards, such as boiler tune-ups, for controlling emissions of organic HAPs and dioxin/furans. Compliance is required within three years of the effective date of the final rule, which is expected by November 2011 per the Federal EPA’s settlement agreement with several environmental groups. A one-year extension may be available if the extension is necessary for the installation of controls. Management is developing comments to structuresubmit to the MACT standards. agency and collecting additional information regarding the performance of the coal-fired units. Comments will be accepted for 60 days after the rule is published in the Federal Register.
Management will urge the Federal EPA to carefully consider all of the options available so that costly and inefficient control requirements are not imposed regardless of unit size, age or other operating characteristics. However, theThe AEP System has approximately 5,0005,500 MW of older coal units including 2,000 MW of older coal-fired capacity already subject to control requirements under the NSR consent decree, for which it may be economically inefficient to install scrubbers or other environmental controls.
Regional Haze – Oklahoma Affecting PSO
In March 2011, the Federal EPA proposed to approve in part and disapprove in part the regional haze state implementation plan (SIP) submitted by the State of Oklahoma through the Department of Environmental Quality. The timing and ultimate disposition of those units will be affected by: a) the MACT standards and other environmental regulations, b) the economics of maintaining the units, c) demand for electricity, d) availability and cost of replacement power and e) regulatory decisions about cost recoveryFederal EPA is proposing to approve all of the remaining investmentNOx control measures in those units.the SIP and disapprove the SO2 control measures for six electric generating units, including two units owned by PSO. The Federal EPA is proposing a federal implementation plan (FIP) that would require these units to install technology capable of reducing SO2 emissions to 0.06 pounds per million British thermal unit within three years of the effective date of the FIP. The proposal is open for public comment.
Coal Combustion Residual Rule
In June 2010, the Federal EPA published a proposed rule to regulate the disposal and beneficial re-use of coal combustion residuals, including fly ash and bottom ash generated at the coal-fired electric generating units. The rule contains two alternative proposals, one that would impose federal hazardous waste disposal and management standards on these materials and one that would allow states to retain primary authority to regulate the beneficial re-use and disposal of these materials under state solid waste management standards, including minimum federal standards for disposal and management. Both proposals would impose stringent requirements for the construction of new coal ash landfills and would require existing unlined surface impoundments to upgrade to the new standards or stop receiving coal ash and init iateinitiate closure within five years of the issuance of a final rule.
Currently, approximately 40% of the coal ash and other residual products from the AEP System’s generating facilities are re-used in the production of cement and wallboard, as structural fill or soil amendments, as abrasives or road treatment materials and for other beneficial uses. Certain of these uses would no longer be available and others are likely to significantly decline if coal ash and related materials are classified as hazardous wastes. In addition, surface impoundments and landfills to manage these materials are currently used at the generating facilities. The Registrant Subsidiaries will incur significant costs to upgrade or close and replace their existing facilities. Management estimates that the potential compliance costs associated with the proposed solid waste m anagementmanagement alternative could be as high as a total of $3.9 billion including AFUDC for units across the AEP System. Regulation of these materials as hazardous wastes would significantly increase these costs.
Clean Water Act Regulations
In March 2011, the Federal EPA Administrator signed a proposed rule setting forth standards for existing power plants that will reduce mortality of aquatic organisms pinned against the plant’s cooling water intake screen (impingement) or entrained in the cooling water. Entrainment is when small fish, eggs or larvae are drawn into the cooling water system and affected by heat, chemicals or physical stress. The Registrant Subsidiaries will seek recoveryproposed standards affect all plants withdrawing more than two million gallons of expenditurescooling water per day and establish specific intake design and intake velocity standards meant to allow fish to avoid or escape impingement. Compliance with this standard is required within eight years of the effective date of the final rule. The proposed standard for pollution control technologiesentrainment requires closed cycle cooling or a site-specific evaluation of the available measures for reducing entrainment. Plants withdrawing more than 125 million gallons of cooling water per day must submit a detailed technology study to be reviewed by the state permitting authority. Management is evaluating the proposal and associated costs from customers through regulated rates or market prices for electricity. If these costsengaged in the collection of additional information regarding the feasibility of implementing this proposal at the AEP System’s facilities. Comments on the proposal are not recovered, it will have a material adverse impact on net income, cash flows and financial condition.due within 90 days after the rule is published in the Federal Register.
Global Warming
While comprehensive economy-wide regulation of CO2 emissions might be achieved through new legislation, Congress has yet to enact such legislation. The Federal EPA continues to take action to regulate CO2 emissions under the existing requirements of the CAA. The Federal EPA issued a final endangerment finding for CO2 emissions from new motor vehicles in December 2009 and final rules for new motor vehicles in May 2010. The Federal EPA determined that CO2 emissions from stationary sources will be subject to regul ationregulation under the CAA beginning in January 2011 at the earliest and finalized its proposed scheme to streamline and phase-in regulation of stationary source CO2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs. Theseprograms through the issuance of final federal rules, have been challenged in the courts.state implementation plan calls and federal implementation plans. The Federal EPA is reconsidering whether to include CO2 emissions in a number of
stationary source standards, including standards that apply to new and modified electric utility units.units and announced a settlement agreement to issue proposed new source performance standards for utility boilers that would be applicable for both new and existing utility boilers. It is not possible at this time to estimate the costs of compliance with these new standards, but they may be material.
The Registrant Subsidiaries’ fossil fuel-fired generating units are very large sources of CO2 emissions. If substantial CO2 emission reductions are required, there will be significant increases in capital expenditures and operating costs which would impact the ultimate retirement of older, less-efficient, coal-fired units. To the extent the Registrant Subsidiaries install additional controls on their generating plants to limit CO2 emissions and receive regulatory approvals to increase rates, cost recovery could have a positive effect on future earnings. Prudently incurred capit alcapital investments made by the Registrant Subsidiaries in rate-regulated jurisdictions to comply with legal requirements and benefit customers are generally included in rate base for recovery and earn a return on investment. Management would expect these principles to apply to investments made to address new environmental requirements. However, requests for rate increases reflecting these costs can affect the Registrant Subsidiaries adversely because the regulators could limit the amount or timing of increased costs that would be recoverable through higher rates. In addition, to the extent the Registrant Subsidiaries’ costs are relatively higher than their competitors’ costs, such as operators of nuclear generation, it could reduce off-system sales or cause the Registrant Subsidiaries to lose customers in jurisdictions that permit customers to choose their supplier of generation service.
Several states have adopted programs that directly regulate CO2 emissions from power plants, but none of these programs are currently in effect in states where the Registrant Subsidiaries have generating facilities. Certain states, including Ohio, Michigan, Texas and Virginia, passed legislation establishing renewable energy, alternative energy and/or energy efficiency requirements. The Registrant Subsidiaries areManagement is taking steps to comply with these requirements.
Certain groups have filed lawsuits alleging that emissions of CO2 are a “public nuisance” and seeking injunctive relief and/or damages from small groups of coal-fired electricity generators, petroleum refiners and marketers, coal companies and others. The Registrant Subsidiaries have been named in pending lawsuits, which management is vigorously defending. It is not possible to predict the outcome of these lawsuits or their impact on operations or financial condition. See “Carbon Dioxide Public Nuisance Claims” and “Alaskan Villages’ Claims” sections of Note 4.3.
Future federal and state legislation or regulations that mandate limits on the emission of CO2 would result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force the Registrant Subsidiaries to close some coal-fired facilities and could lead to possible impairment of assets. As a result, mandatory limits could have a material adverse impact on net income, cash flows and financial condition.
For detailed information on global warming and the actions the AEP System is taking address potential impacts, see Part I of the 20092010 Form 10-K under the headings entitled “Business – General – Environmental and Other Matters – Global Warming and “Combined Management Discussion and Analysis of Registrant Subsidiaries.”
FINANCIAL CONDITION AND CAPITAL RESOURCES
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 operate a money pool to minimize the AEP System’s external short-term funding requirements and sell accounts receivable to provide liquidity. Under credit facilities, $1.35 billion may be issued as letters of credit (LOC). 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-leasebacks, leasing arrangements and additional capital contributions fro mfrom Parent.
In March 2011, the Registrant Subsidiaries and certain other companies in the AEP System entered intoterminated a 3-year$478 million credit agreement which maturesfacility, used for letters of credit to support variable rate debt, that was scheduled to mature in April 2011. In June 2010, theMarch 2011, APCo, I&M and OPCo issued bilateral letters of credit facility was reduced from $627 million to $478 million. The Registrant Subsidiaries may issue LOCs under the credit facility. Each subsidiary has a borrowing/LOC limit under the credit facility. As of September 30, 2010, a total of $477 million of LOCs were issued under the credit agreement to support the remarketing of $230 million, $77 million and $50 million, respectively, of their variable rate demand notes. The following table shows each Registrant Subsidiaries’ borrowing/LOC limit under the credit facility and the outstanding amount of LOCs.
| | | | | LOC Amount | |
| | | | | Outstanding | |
| | Credit Facility | | | Against the | |
| | Borrowing/LOC | | | Agreement at | |
Company | | Limit | | | September 30, 2010 | |
| | (in millions) | |
APCo | | $ | 300 | | | $ | 232 | |
CSPCo | | | 230 | | | | - | |
I&M | | | 230 | | | | 78 | |
OPCo | | | 400 | | | | 167 | |
PSO | | | 65 | | | | - | |
SWEPCo | | | 230 | | | | - | |
debt. OPCo reacquired $115 million which is held by a trustee on its behalf.
Dividend Restrictions
Under the Federal Power Act, the Registrant Subsidiaries are restricted from paying dividends out of stated capital. Various financing arrangements, charter provisions and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends.
Sales of Receivables
In July 2010, AEP Credit renewed its receivables securitization agreement. The agreement provides a commitment of $750 million from bank conduits to purchase receivables. A commitment of $375 million expires in July 2011 and the remaining commitment of $375 million expires in July 2013. Management intends to extend or replace the agreement expiring in July 2011 on or before its maturity. AEP Credit purchases accounts receivable from the Registrant Subsidiaries.
MINE SAFETY INFORMATION
The Federal Mine Safety and Health Act of 1977 (Mine Act) imposes stringent health and safety standards on various mining operations. The Mine Act and its related regulations affect numerous aspects of mining operations, including training of mine personnel, mining procedures, equipment used in mine emergency procedures, mine plans and other matters. SWEPCo, through its ownership of DHLC, CSPCo, through its ownership of Conesville Coal Preparation Company (CCPC), and OPCo, through its use of the ConnorConner Run fly ash impoundment, are subject to the provisions of the Mine Act.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires companies that operate mines to include in their periodic reports filed with the SEC, certain mine safety information covered by the Mine Act. DHLC, CCPC and ConnorConner Run received the following notices of violation and proposed assessments under the Mine Act for the quarter ended September 30, 2010:March 31, 2011:
| | | DHLC | | CCPC | | Conner Run |
Number of Citations for Violations of Mandatory Health or | | | | | | | | | |
| Safety Standards under 104 * | | | 7- | | | - | | | - |
Number of Orders Issued under 104(b) * | | | - | | | - | | | - |
Number of Citations and Orders for Unwarrantable Failure | | | | | | | | | |
| to Comply with Mandatory Health or Safety Standards under104(d) * | | | | | | | | | |
| 104(d) * | | | 1- | | | - | | | - |
Number of Flagrant Violations under 110(b)(2) * | | | - | | | - | | | - |
Number of Imminent Danger Orders Issued under 107(a) * | | | - | | | - | | | - |
Total Dollar Value of Proposed Assessments | | $ | 11,4722,144 | | $ | - | | $ | - |
Number of Mining-related Fatalities | | | - | | | - | | | - |
| | | | | | | | | |
* References to sections under the Mine Act | | | | | | | | | |
DHLC currently has twoa legal actionsaction pending before the Mine Safety and Health Administration (MSHA) challenging four violations issued by MSHA following an employee fatality in March 2009. A second legal action pending before MSHA relates to a citation issued as a result of a dragline boom issue.
ACCOUNTING PRONOUNCEMENTS
New Accounting Pronouncement Adopted During 2010
The Registrant Subsidiaries prospectively adopted ASU 2009-17 “Consolidation” effective January 1, 2010. SWEPCo no longer consolidates DHLC effective with the adoption of this standard.
See Note 2 for further discussion of accounting pronouncements.
Future Accounting Changes
The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued, 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, financial statements, contingencies, financial instruments, emission allowances, fair value measurements, leases, insurance, hedge accounting, consolidation policy and discontinued operations. 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 financ ialfinancial position.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK MANAGEMENT ACTIVITIES
Market Risks
The Registrant Subsidiaries’ 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”Market Risk” section. Also, see Note 87 – Derivatives and Hedging and Note 98 – Fair Value Measurements for additional information related to the Registrant Subsidiaries’ risk management contracts.
The following tables summarize the reasons for changes in total mark-to-market (MTM) value as compared to December 31, 2009:2010:
| MTM Risk Management Contract Net Assets (Liabilities) |
| Nine Months Ended September 30, 2010 |
| (in thousands) |
| | |
| | |
APCo | |
Total MTM Risk Management Contract Net Assets at December 31, 2009 | $ | 45,197 |
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | | (21,694) |
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 | | (245) |
Changes in Fair Value Due to Market Fluctuations During the Period (c) | | 61 |
Changes in Fair Value Allocated to Regulated Jurisdictions (d) | | 9,815 |
Total MTM Risk Management Contract Net Assets | | 33,134 |
Cash Flow Hedge Contracts | | (4,513) |
DETM Assignment (e) | | (632) |
Collateral Deposits | | 40,554 |
Total MTM Derivative Contract Net Assets at September 30, 2010 | $ | 68,543 |
| | | |
OPCo | |
Total MTM Risk Management Contract Net Assets at December 31, 2009 | $ | 26,330 |
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | | (12,940) |
Fair Value of New Contracts at Inception When Entered During the Period (a) | | 7,641 |
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts (b) | | (715) |
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered | | |
| During the Period | | (363) |
Changes in Fair Value Due to Market Fluctuations During the Period (c) | | 6,615 |
Changes in Fair Value Allocated to Regulated Jurisdictions (d) | | (5,062) |
Total MTM Risk Management Contract Net Assets | | 21,506 |
Cash Flow Hedge Contracts | | (2,320) |
DETM Assignment (e) | | (445) |
Collateral Deposits | | 28,660 |
Total MTM Derivative Contract Net Assets at September 30, 2010 | $ | 47,401 |
MTM Risk Management Contract Net Assets (Liabilities) | |
Three Months Ended March 31, 2011 | |
(in thousands) | |
| | |
APCo | | |
| | | |
Total MTM Risk Management Contract Net Assets at December 31, 2010 | | $ | 26,882 | |
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | | | (6,740 | ) |
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 | | | (23 | ) |
Changes in Fair Value Due to Market Fluctuations During the Period (b) | | | (202 | ) |
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | | | 6,248 | |
Total MTM Risk Management Contract Net Assets | | | 26,165 | |
Cash Flow Hedge Contracts | | | 250 | |
Collateral Deposits | | | 16,689 | |
Total MTM Derivative Contract Net Assets at March 31, 2011 | | $ | 43,104 | |
PSO | |
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2009 | $ | (369) |
(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 | | (42) |
Changes in Fair Value Due to Market Fluctuations During the Period (c) | | (7) |
Changes in Fair Value Allocated to Regulated Jurisdictions (d) | | 3,190 |
Total MTM Risk Management Contract Net Assets | | 3,035 |
Cash Flow Hedge Contracts | | - |
DETM Assignment (e) | | (16) |
Collateral Deposits | | 55 |
Total MTM Derivative Contract Net Assets at September 30, 2010 | $ | 3,074 |
| | | |
SWEPCo | |
Total MTM Risk Management Contract Net Assets at December 31, 2009 | $ | 1,636 |
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | | (1,422) |
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 | | (101) |
Changes in Fair Value Due to Market Fluctuations During the Period (c) | | - |
Changes in Fair Value Allocated to Regulated Jurisdictions (d) | | 1,530 |
Total MTM Risk Management Contract Net Assets | | 1,643 |
Cash Flow Hedge Contracts | | (71) |
DETM Assignment (e) | | (19) |
Collateral Deposits | | 88 |
Total MTM Derivative Contract Net Assets at September 30, 2010 | $ | 1,641 |
| | | | |
OPCo | | | | |
| | | | |
Total MTM Risk Management Contract Net Assets at December 31, 2010 | | $ | 18,264 | |
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | | | (4,665 | ) |
Fair Value of New Contracts at Inception When Entered During the Period (a) | | | 968 | |
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During the Period | | | (75 | ) |
Changes in Fair Value Due to Market Fluctuations During the Period (b) | | | 2,672 | |
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | | | 742 | |
Total MTM Risk Management Contract Net Assets | | | 17,906 | |
Cash Flow Hedge Contracts | | | 208 | |
Collateral Deposits | | | 11,466 | |
Total MTM Derivative Contract Net Assets at March 31, 2011 | | $ | 29,580 | |
| | | | |
PSO | | | | |
| | | | |
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2010 | | $ | (378 | ) |
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | | | 134 | |
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 | | | (12 | ) |
Changes in Fair Value Due to Market Fluctuations During the Period (b) | | | 48 | |
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | | | (525 | ) |
Total MTM Risk Management Contract Net Assets (Liabilities) | | | (733 | ) |
Cash Flow Hedge Contracts | | | 376 | |
Collateral Deposits | | | 2 | |
Total MTM Derivative Contract Net Assets (Liabilities) at March 31, 2011 | | $ | (355 | ) |
| | | | |
SWEPCo | | | | |
| | | | |
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2010 | | $ | (2,958 | ) |
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period | | | 1,046 | |
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 | | | (21 | ) |
Changes in Fair Value Due to Market Fluctuations During the Period (b) | | | 88 | |
Changes in Fair Value Allocated to Regulated Jurisdictions (c) | | | 305 | |
Total MTM Risk Management Contract Net Assets (Liabilities) | | | (1,540 | ) |
Cash Flow Hedge Contracts | | | 355 | |
Collateral Deposits | | | 3 | |
Total MTM Derivative Contract Net Assets (Liabilities) at March 31, 2011 | | $ | (1,182 | ) |
(a) | Reflects fair value on primarily 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) | Reflects changes in methodology in calculating the credit and discounting liability fair value adjustments. |
(c) | Market fluctuations are attributable to various factors such as supply/demand, weather, etc. |
(d)(c) | 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 liabilities/assets. |
(e) | See “Natural Gas Contracts with DETM” section of Note 15 of the 2009 Annual Report. |
The following tables present the maturity, by year, of net assets/liabilities to give an indication of when these MTM amounts will settle and generate or (require) cash:
Maturity and Source of Fair Value of MTM | Risk Management Contract Net Assets (Liabilities) | September 30, 2010 | |
(in thousands) | |
March 31, 2011 | | March 31, 2011 |
| | | | | | | | | | |
| | Remainder | | | | | | | | Remainder | | | | | | |
APCo | APCo | 2010 | | 2011-2013 | | 2014+ | | Total | APCo | 2011 | | 2012-2014 | | 2015+ | | Total |
| | | (in thousands) |
Level 1 (a) | Level 1 (a) | $ | 25 | | $ | 36 | | $ | - | | $ | 61 | Level 1 (a) | $ | 27 | | $ | 1 | | $ | - | | $ | 28 |
Level 2 (b) | Level 2 (b) | | 3,183 | | | 7,092 | | 1,411 | | 11,686 | Level 2 (b) | | 1,060 | | | 14,898 | | 1,552 | | 17,510 |
Level 3 (c) | Level 3 (c) | | 1,497 | | | 11,391 | | | 3,677 | | | 16,565 | Level 3 (c) | | 1,158 | | | 4,070 | | | 244 | | | 5,472 |
Total | Total | | 4,705 | | | 18,519 | | 5,088 | | 28,312 | Total | | 2,245 | | | 18,969 | | 1,796 | | 23,010 |
Dedesignated Risk Management | Dedesignated Risk Management | | | | | | | | | | Dedesignated Risk Management | | | | | | | | | |
| Contracts (d) | | 1,451 | | | 3,371 | | | - | | | 4,822 | Contracts (d) | | 1,546 | | | 1,609 | | | - | | | 3,155 |
Total MTM Risk Management | Total MTM Risk Management | | | | | | | | | Total MTM Risk Management | | | | | | | | |
| Contract Net Assets | $ | 6,156 | | $ | 21,890 | | $ | 5,088 | | $ | 33,134 | Contract Net Assets | $ | 3,791 | | $ | 20,578 | | $ | 1,796 | | $ | 26,165 |
| | | | | | | | | | | | | | | | | | |
| | Remainder | | | | | | | | Remainder | | | | | | |
OPCo | OPCo | 2010 | | 2011-2013 | | 2014+ | | Total | OPCo | 2011 | | 2012-2014 | | 2015+ | | Total |
| | | (in thousands) |
Level 1 (a) | Level 1 (a) | $ | 18 | | $ | 26 | | $ | - | | $ | 44 | Level 1 (a) | $ | 18 | | $ | 1 | | $ | - | | $ | 19 |
Level 2 (b) | Level 2 (b) | | 1,017 | | | 4,402 | | 993 | | 6,412 | Level 2 (b) | | 372 | | | 10,524 | | 1,066 | | 11,962 |
Level 3 (c) | Level 3 (c) | | 1,054 | | | 8,016 | | | 2,587 | | | 11,657 | Level 3 (c) | | 797 | | | 2,795 | | | 167 | | | 3,759 |
Total | Total | | 2,089 | | | 12,444 | | 3,580 | | 18,113 | Total | | 1,187 | | | 13,320 | | 1,233 | | 15,740 |
Dedesignated Risk Management | Dedesignated Risk Management | | | | | | | | | | Dedesignated Risk Management | | | | | | | | | |
| Contracts (d) | | 1,021 | | | 2,372 | | | - | | | 3,393 | Contracts (d) | | 1,061 | | | 1,105 | | | - | | | 2,166 |
Total MTM Risk Management | Total MTM Risk Management | | | | | | | | | Total MTM Risk Management | | | | | | | | |
| Contract Net Assets | $ | 3,110 | | $ | 14,816 | | $ | 3,580 | | $ | 21,506 | Contract Net Assets | $ | 2,248 | | $ | 14,425 | | $ | 1,233 | | $ | 17,906 |
| | Remainder | | | | | | |
PSO | 2010 | | 2011-2013 | | Total |
Level 1 (a) | $ | 1 | | $ | - | | $ | 1 |
Level 2 (b) | | 1,731 | | | 1,301 | | | 3,032 |
Level 3 (c) | | 2 | | | - | | | 2 |
Total MTM Risk Management | | | | | | | | |
| Contract Net Assets | $ | 1,734 | | $ | 1,301 | | $ | 3,035 |
| | | | | | | | | |
| | Remainder | | | | | | |
SWEPCo | 2010 | | 2011-2013 | | Total |
Level 1 (a) | $ | 1 | | $ | - | | $ | 1 |
Level 2 (b) | | 992 | | | 648 | | | 1,640 |
Level 3 (c) | | 2 | | | - | | | 2 |
Total MTM Risk Management | | | | | | | | |
| Contract Net Assets | $ | 995 | | $ | 648 | | $ | 1,643 |
| | | Remainder | | | | | | |
| PSO | 2011 | | 2012-2014 | | Total |
| | | (in thousands) |
| Level 1 (a) | $ | - | | $ | - | | $ | - |
| Level 2 (b) | | (781) | | | 48 | | | (733) |
| Level 3 (c) | | - | | | - | | | - |
| Total MTM Risk Management | | | | | | | | |
| | Contract Net Assets (Liabilities) | $ | (781) | | $ | 48 | | $ | (733) |
| | | | | | | | | | |
| | | Remainder | | | | | | |
| SWEPCo | 2011 | | 2012-2014 | | Total |
| | | (in thousands) |
| Level 1 (a) | $ | - | | $ | - | | $ | - |
| Level 2 (b) | | (1,635) | | | 95 | | | (1,540) |
| Level 3 (c) | | - | | | - | | | - |
| Total MTM Risk Management | | | | | | | | |
| | Contract Net Assets (Liabilities) | $ | (1,635) | | $ | 95 | | $ | (1,540) |
(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 the accounting guidance for “Derivatives and Hedging.” 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 contracts. |
Credit Risk
Counterparty credit quality and exposure of the Registrant Subsidiaries is generally consistent with that of AEP.
Value at Risk (VaR) Associated with Risk Management Contracts
Management uses a risk measurement model, which calculates 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, 2010,March 31, 2011, a near term typical change in commodity prices is not expected to have a material effect on 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 trading portfolio for the periods indicated:
| Nine Months Ended | | Twelve Months Ended | | Three Months Ended | | Twelve Months Ended | |
| September 30, 2010 | | December 31, 2009 | | March 31, 2011 | | December 31, 2010 | |
Company | | End | | High | | Average | | Low | | End | | High | | Average | | Low | | End | | High | | Average | | Low | | End | | High | | Average | | Low | |
| | | | | | | | | | | | | | | | | | |
| (in thousands) | | (in thousands) | | (in thousands) | | (in thousands) | |
APCo | | $ | 96 | | $ | 659 | | $ | 216 | | $ | 71 | | $ | 275 | | $ | 699 | | $ | 333 | | $ | 151 | | | $ | 101 | | | $ | 231 | | | $ | 120 | | | $ | 67 | | | $ | 124 | | | $ | 659 | | | $ | 193 | | | $ | 71 | |
OPCo | | | 82 | | | 545 | | | 180 | | | 54 | | | 201 | | | 530 | | | 244 | | 113 | | | | 90 | | | | 221 | �� | | | 120 | | | | 64 | | | | 100 | | | | 545 | | | | 161 | | | | 54 | |
PSO | | | 14 | | | 70 | | | 17 | | | 1 | | | 10 | | | 34 | | | 12 | | 4 | | | | 4 | | | | 32 | | | | 15 | | | | 4 | | | | 3 | | | | 70 | | | | 15 | | | | 1 | |
SWEPCo | | | 20 | | | 93 | | | 24 | | | 2 | | | 16 | | | 49 | | | 18 | | 6 | | | | 8 | | | | 46 | | | | 23 | | | | 7 | | | | 6 | | | | 93 | | | | 21 | | | | 2 | |
Management back-tests its VaR results against performance due to actual price movements. Based on the assumed 95% confidence interval, the performance due to actual price movements would be expected to exceed the VaR at least once every 20 trading days.
As the VaR calculations capture recent price movements, management also performs regular stress testing of the portfolio to understand the exposure to extreme price movements. Management employs a historical-based method whereby the current portfolio is subjected to actual, observed price movements from the last four years in order to ascertain which historical price movements translated into the largest potential MTM loss. Management then researches the underlying positions, price movements and market events that created the most significant exposure and reportreports the findings to the Risk Executive Committee or the Commercial Operations Risk Committee as appropriate.
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 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. As calculated on the Registrant Subsidiaries’ outstanding debt as of September 30, 2010March 31, 2011 and December 31, 2009,2010, the estimated EaR on the Registrant Subsidiaries’ debt portfolio was as follows:
| | September 30, | | December 31, | | March 31, | | | December 31, | |
Company | | 2010 | | 2009 | | 2011 | | | 2010 | |
| | (in thousands) | | (in thousands) | |
APCo | | $ | 1,301 | | $ | 1,837 | | $ | 634 | | | $ | 1,165 | |
CSPCo | | 202 | | | 216 | | | 176 | | | | 178 | |
I&M | | 337 | | | 227 | | | 444 | | | | 274 | |
OPCo | | 1,058 | | | 1,373 | | | 738 | | | | 926 | |
PSO | | 43 | | | 119 | | | 36 | | | | 658 | |
SWEPCo | | 666 | | | 305 | | | 920 | | | | 1,027 | |
CONTROLS AND PROCEDURES
During the thirdfirst quarter of 2010,2011, management, including the principal executive officer and principal financial officer of each of AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo (collectively, the Registrants), evaluated the Registrants’ disclosure controls and procedures. Disclosure controls and procedures are defined as controls and other procedures of the Registrants that are designed to ensure that information required to be disclosed by the Registrants in the reports that they file or submit under the Exchange Act are recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Registrants in t hethe reports that they file or submit under the Exchange Act is accumulated and communicated to the Registrants’ management, including the principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
As of September 30, 2010,March 31, 2011, these officers concluded that the disclosure controls and procedures in place are effective and provide reasonable assurance that the disclosure controls and procedures accomplished their objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of their financial reporting and to maintain dynamic systems that change as events warrant.
There was no change in the Registrants’ internal control over financial reporting (as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) during the thirdfirst quarter of 20102011 that materially affected, or is reasonably likely to materially affect, the Registrants’ internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
For a discussion of material legal proceedings, see “Commitments, Guarantees and Contingencies,” of Note 43 incorporated herein by reference.
Item 1A. Risk Factors
OurThe Annual Report on Form 10-K for the year ended DecemberMarch 31, 20092011 includes a detailed discussion of our risk factors. The information presented below amends and restates in their entirety certain of those risk factors that have been updated and should be read in conjunction with the risk factors and information disclosed in our 2009the 2010 Annual Report on Form 10-K.
General Risks of Our Regulated OperationsRISKS RELATING TO REGULATED OPERATIONS
We may not fully recover allAll of the investment in and expenses related to the Turk Plant.(Applies toPlant may not be fully recovered. – Affecting AEP and SWEPCo) SWEPCo |
In June 2010,SWEPCo is in the APSC issued an order which reversed and set asideprocess of building the previously granted CECPN. SWEPCo filed a notice with the APSC of its intent to proceed with construction of theJohn W. Turk Plant but that SWEPCo no longer intends to pursue(Turk Plant) in southwest Arkansas and holds a CECPN to seek recovery of73% ownership interest in the originally approved 88planned 600 MW portion of Turk Plant costscoal-fired generating facility. Its construction and anticipated operation have resulted in Arkansas retail rates.numerous legal challenges and uncertainties, including:
In November 2008, SWEPCo received its required air permit approval from the Arkansas Department of Environmental Quality and commenced construction at the site. The Arkansas Pollution Control and Ecology Commission (APCEC) upheld the air permit. In February 2010, the parties who unsuccessfully appealed the air permit to the APCEC filed a notice of appeal with the Circuit Court of Hempstead County, Arkansas.· | The validity of the air permit issued by the Arkansas Pollution Control and Ecology Commission in connection with the operation of the Turk Plant; |
· | The validity of the wetlands permit issued by the U.S. Army Corps of Engineers in connection with the construction and operation of the Turk Plant; |
The wetlands permit was issued by the U.S. Army Corps of Engineers in December 2009. In February 2010, the Sierra Club, the Audubon Society and others filed a complaint in the Federal District Court for the Western District of Arkansas against the U.S. Army Corps of Engineers challenging the process used and the terms of the permit issued to SWEPCo authorizing certain wetland and stream impacts. In May 2010, plaintiffs filed with the Federal District Court for the Western District of Arkansas seeking a preliminary injunction to halt construction and for a temporary restraining order. · | Whether SWEPCo is required to obtain APSC approval to construct the Turk Plant without pursuing authority to seek recovery of the originally approved 88 MW portion of Turk Plant costs in Arkansas retail rates; |
· | The validity of PUCT approval of the Texas jurisdictional cost recovery and uncertainty regarding the caps on recovery included in the approval; and |
In July 2010, the Hempstead County Hunting Club filed a complaint with the Federal District Court for the Western District of Arkansas against SWEPCo, the U.S. Army Corps of Engineers, the U.S. Department of Interior and the U.S. Fish and Wildlife Service seeking a temporary restraining order and preliminary injunction to stop construction of the Turk Plant asserting claims of violations of federal and state laws. This motion for preliminary injunction was heard simultaneously with the motion filed by the Sierra Club. In October 2010, the motions for preliminary injunction were partially granted. According to the preliminary injunction, all uncompleted construction work associated with wetlands, streams or rivers at the Turk Plant must immediately stop. Mitigation measures required by the permit are authorized and may be completed. The preliminary injunction affects portions of the water intake and associated piping and portions of the transmission lines. In October 2010, the Federal District Court certified issues relating to the state law claims to the Arkansas Supreme Court, including whether those claims are within the primary jurisdiction of the APSC. The Arkansas Supreme Court has yet to consider the request. SWEPCo filed a notice of appeal with the Federal Court of Appeals for the Eighth Circuit and is seeking a stay of the preliminary injunction pending appeal.
In January 2009, SWEPCO was granted CECPNs by the APSC to build three transmission lines and facilities authorized by the SPP and needed to transmit power from the Turk Plant. Intervenors appealed the CECPN decisions in April 2009 to the Arkansas Court of Appeals. In July 2010, the Hempsted County Hunting Club and other appellants filed with the Arkansas Court of Appeals emergency motions to stay the transmission CECPNs to prohibit SWEPCo from taking ownership of private property and undertaking construction of the transmission lines. In July 2010, the Arkansas Court of Appeals issued a decision remanding all transmission line CECPN appeals to the APSC. As a result, a stay was not ordered and construction continues on the affected transmission lines.· | A complaint filed in the Federal District Court for the Western District of Arkansas against SWEPCo, the U.S. Army Corps of Engineers, the U.S. Department of Interior and the U.S. Fish and Wildlife Service seeking a temporary restraining order and preliminary injunction to stop construction of the Turk Plant asserting claims of violations of various federal and state laws. |
If SWEPCo is unable to complete the Turk Plant construction and place the Turk Plant in service or if SWEPCo cannot recover all of its investment in and expenses related to the Turk Plant, it would materially reduce future net income and cash flows and materially impact financial condition.
Rate recovery approved in Ohio may require usbe overturned on appeal, may not provide full recovery of fuel costs and/or may have to refund revenue that we have collected. (Applies tobe returned. – Affecting AEP, CSPCo and CSPCo)OPCo
Ohio law requiresThe PUCO issued an order in March 2009 that modified and approved the Electric Security Plans (ESPs) of CSPCo and OPCo. The ESPs established rates in effect through 2011. The ESP order generally authorized rate increases during the ESP period, subject to caps that limit the rate increases, and also provides a fuel adjustment clause for the three-year period of the ESPs. The recovery includes deferrals associated with the Ormet interim arrangement and is subject to the PUCO’s ultimate decision regarding the Ormet interim arrangement deferrals plus related carrying charges. If the PUCO determine, followingand/or the endSupreme Court of each yearOhio reverses all or part of the ESP,rate recovery or if rate adjustments included indeferred fuel costs are not fully recovered for other reasons, it could reduce future net income and cash flows and impact financial condition. In April 2011, the ESPSupreme Court of Ohio issued an opinion addressing the aspects of the PUCO's 2009 decision that were challenged which resulted in significantly excessive earnings.three reversals, only two of which may have a prospective impact. If any rate changes result from the PUCO’s remand proceedings, such rate adjustments, inchanges would be prospective from the aggregate, result in significantly excessive earnings,date of the excess amount could be returned to customers. remand order through the remaining months of 2011.
Request for rate and other recovery in Ohio for distribution service may not be approved in its entirety. – Affecting AEP, CSPCo and OPCo |
In September 2010,February 2011, CSPCo and OPCo filed their 2009 SEET filings with the PUCO. CSPCo’sPUCO for an annual increase in distribution rates of $34 million and OPCo’s returns on common equity were 20.84% and 10.81%, respectively, including off-system sales margins and 18.31% and 9.42%, respectively, excluding off-system sales margins. Included in the filings was CSPCo’s and OPCo’s determination that the level at which their earned$60 million, respectively. The requested increase is based upon an 11.15% return on common equity may become significantly in excess ofto be effective January 2012. In addition to the average earned return on common equi ty of the comparable risk group of publicly traded firms was 22.51%. Based upon the methodology proposed byannual increase, CSPCo and OPCo requested recovery of the projected December 31, 2012 balance of certain distribution regulatory assets of $216 million and $159 million, respectively, including approximately $102 million and $84 million, respectively, of unrecognized equity carrying costs. These assets would be recovered in the SEET filings, neither CSPCo’s nor OPCo’s 2009 return on common equity was significantly excessive. In October 2010, intervenors filed testimonya distribution asset recovery rider over seven years with the PUCO recommending CSPCo return up to $156 million of its ESP revenues to customers.additional carrying costs, beginning January 2013. If the PUCO determines that CSPCo’s and/denies all or OPCo’s 2009 return on common equity was significantly excessive, CSPCo and/or OPCo may be required to return a portion of their ESP revenues to customers.
Ohio may require us to refund fuel costs that we have collected. (Applies to OPCo)
As required under the ESP orders, the PUCO selected an outside consultant to conduct the auditpart of the FAC for the period of January 2009 through December 2009. In May 2010, the outside consultant provided their confidential audit report of the FAC audit to the PUCO. The audit report included a recommendation that the PUCO should review whether any proceeds from a 2008 coal contract settlement agreement which totaled $72 million should reduce OPCo’s FAC under-recovery balance. Of the total proceeds, approximately $58 million was recognized as a reduction to fuel expense prior to 2009requested rate and $14 million will reduce fuel expense in 2009 and 2010. If the PUCO orders any portion of the $58 million previously recognized or potential other future adjustments be used to reduce the current year F AC deferral,recovery, it wouldcould reduce future net income and cash flows and impact financial condition.
Ohio may require us to refund rider revenue that we have collected. (Applies to CSPCo and OPCo)
The Industrial Energy Users-Ohio filed a notice of appeal of the 2009 and 2010 PUCO-approved Economic Development Rider (EDR) with the Supreme Court of Ohio. As of September 30, 2010, CSPCo and OPCo have incurred $39 million and $30 million, respectively, in EDR costs including carrying costs. Of these costs, CSPCo and OPCo have collected $27 million and $20 million, respectively, through the EDR, which CSPCo and OPCo began collecting in January 2010. The remaining $12 million and $10 million for CSPCo and OPCo, respectively, are recorded as EDR regulatory assets. If CSPCo and OPCo are not ultimately permitted to recover their deferrals or are required to refund revenue collected, it would reduce future net income and cash flows and impact financial condition.
Texas may require us to refund fuel costs that we have collected. (Applies to SWEPCo)
In May 2010, various intervenors, including the PUCT staff, filed testimony recommending disallowances ranging from $3 million to $30 million in SWEPCo’s $755 million fuel and purchase power costs reconciliation for the period January 2006 through March 2009. In July 2010, Cities Advocating Reasonable Deregulation filed testimony regarding the 2007 transfer of ERCOT trading contracts to AEPEP. Included in this testimony were unquantified refund recommendations relating to re-pricing of contract transactions.
In September 2010, the Administrative Law Judges issued a Proposal for Decision (PFD) that recommended a disallowance of a significant portion of the charges to a ten-year gas transportation agreement that began in 2009 for the Mattison Plant located in Northwest Arkansas. The PFD stated that SWEPCo should have pursued other transportation options or sought the supplier’s recourse rate from the FERC. The estimated recommended disallowance over the ten-year period through December 2018 is $107 million for which the estimated Texas jurisdictional portion is $37 million. In addition, the PFD also contained recommendations to disallow risk premiums related to the ERCOT trading contracts transferred to AEPEP which are estimated to be $1.5 million on a Texas retail jurisdictional basis. Thr ough September 30, 2010, SWEPCo’s management estimated the impact of this PFD, if adopted by the PUCT, to be $7 million. In October 2010, SWEPCo filed exceptions on these issues with the PUCT. An order may be issued in the fourth quarter of 2010. Management is unable to predict the outcome of this reconciliation. If the PUCT disallows any portion of SWEPCo’s fuel and purchase power costs, it could reduce future net income and cash flows and possibly impact financial condition.
Our requestRequest for rate recovery in West VirginiaOhio for generation service may not be approved in its entirety.(Applies to – Affecting AEP, CSPCo and APCo) OPCo |
In May 2010, APCoJanuary 2011, CSPCo and WPCoOPCo filed a requestan application with the WVPSCPUCO to increase annual base rates by $156 million based on an 11.75% return on common equity to beapprove a new ESP that includes a standard service offer pricing for generation effective March 2011.with the first billing cycle of January 2012 through the last billing cycle of May 2014. If the WVPSCPUCO denies all or part of the requested rate recovery, it could reduce future net income and cash flows. The April 2011 decision by the Supreme Court of Ohio referenced above in connection with the 2009-2011 ESPs could impact the outcome of the January 2012 – May 2014 ESP, though the nature and extent of that impact is not presently known.
OklahomaRequest for rate and other recovery in Virginia for generation and distribution service may require us to refund fuel costs that we have collected. (Applies to PSO)not be approved in its entirety. – Affecting AEP and APCo
In July 2009, the OCC initiatedMarch 2011, APCo filed a proceeding to review PSO’s fuelgeneration and purchased power adjustment clause for the calendar year 2008 and also initiated a prudence review of the related costs. In March 2010, the Oklahoma Attorney General and the OIEC recommended the fuel clause adjustment rider be amended so that the shareholder’s portion of off-system sales margins sharing decrease from 25% to 10%. The OIEC also recommended that the OCC conduct a comprehensive review of all affiliate transactions during 2007 and 2008. In July 2010, additional testimony regarding the 2007 transfer of ERCOT trading contracts to AEP Energy Partners was filed. Included in this testimony were unquantified refund recommendations relating to re-pricing of contract transactions. If the OCC were to issue an unfavorable decision, it would reduce future net income and cash flows and impact financial condition.
Our request fordistribution base rate recovery in Oklahoma may not be approved in its entirety.(Applies to AEP and PSO)
|
In July 2010, PSO filed a request with the OCCVirginia SCC to increase annual base rates by $82$126 million including $30 million that is currently being recovered through a rider. The requested increase includes a $24 million increase in depreciation andbased upon an 11.5%11.65% return on common equity.equity to be effective no later than February 2012. APCo proposed to mitigate the requested base rate increase by $51 million by maintaining current depreciation rates until the next biennial filing. If approved, APCo’s net base rate increase would be $75 million. In October 2010,addition, APCo filed for approval of over $40 million in rate adjustment clauses for various parties filed testimony. The parties’ net annual rate recommendations ranged from a rate reduction of $18 millioncosts including environmental and renewable energy and generation costs relating to an increase of less than $1 million.the partially completed Dresden Plant. If the OCCVirginia SCC denies all or part of the requested rate and other recovery, it could reduce future net income and cash flows.
RISKS RELATED TO STATE RESTRUCTURING
Risks Related to State Restructuring
Our customersCustomers have recently begun to select alternative electric generation service providers, as allowed by Ohio legislation. (Applies to – Affecting AEP, CSPCo and CSPCo)OPCo
Under current Ohio legislation, electric generation is sold in a competitive market in Ohio, and our native load customers in Ohio have the ability to switch to alternative suppliers for their electric generation service. Competitive power suppliers are targeting retail customers by offering alternative generation service. A growing number of CSPCo's commercial retail customers (primarily CSPCo’s) have switched to alternative generation providers while additional Ohio customers have provided notice of their intent to switch. As of March 31, 2011, approximately 7,800 Ohio retail customers (primarily CSPCo’s) have switched to alternative generation providers. Although to date OPCo’s losses have not been significant, OPCo could experience additional customer switching in the future. These evolving market conditions maywill continue to impact CSPCo's and OPCo’s results of operations and its ability to apply regulatory accounting treatment to certain portions of its operations.
Risks Related to Owning and Operating Generation Assets and Selling Power
We may not fully recover the costs of repairing or replacing damaged equipment in Cook Plant Unit 1 and may be required to pay additional accidental outage insurance proceeds to ratepayers.(Applies to AEP and I&M)
Cook Plant Unit 1 is a 1,084 MW nuclear generating unit located in Bridgman, Michigan. In September 2008, I&M shut down Unit 1 due to turbine vibrations, caused by blade failure, which resulted in significant turbine damage and a small fire on the electric generator. Unit 1 resumed operations in December 2009 at slightly reduced power, but repair of the property damage and replacement of the turbine rotors and other equipment are estimated to cost approximately $395 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.
In March 2009, the IURC approved a settlement agreement with intervenors to collect a prior under-recovered fuel balance. Under the settlement agreement, a subdocket was established to consider issues relating to the Unit 1 shutdown including the treatment of the accidental outage insurance proceeds. Separately, in March 2010, I&M filed its 2009 PSCR reconciliation with the MPSC. The filing included an adjustment related to the incremental fuel cost of replacement power due to the Cook Plant Unit 1 outage. If any fuel clause revenues or accidental outage insurance proceeds have to be refunded, it would reduce future net income and cash flows and impact financial condition.
Financial derivatives reforms could increase the liquidity needs and costs of our commercial trading operations. (Applies to each registrant.)
In July 2010, federal legislation was enacted to reform financial markets that significantly alter how over-the-counter (OTC) derivatives are regulated. The law increased regulatory oversight of OTC energy derivatives, including (1) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the Commodity Futures Trading Commission (CFTC), (2) imposing new and potentially higher capital and margin requirements and (3) authorizing the establishment of overall volume and position limits. The law gives the CFTC authority to exempt end users of energy commodities which could reduce, but not eliminate, the applicability of these measures to us and other end users. These requirements could cause our OTC transactions to be more costly and have an adverse effect on our liquidity d ue to additional capital requirements. In addition, as these reforms aim to standardize OTC products it could limit the effectiveness of our hedging programs because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to protect.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
The following table provides information about purchases by AEP or its publicly-traded subsidiaries during the quarter ended September 30, 2010March 31, 2011 of equity securities that are registered by AEP or its publicly-traded subsidiaries pursuant to Section 12 of the Exchange Act:
ISSUER PURCHASES OF EQUITY SECURITIES
Period | | Total Number of Shares Purchased | | Average Price Paid per Share | | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs |
07/01/10 – 07/31/10 | | | - | | $ | - | | | | - | | $ | - |
08/01/10 – 08/31/10 | | | 6 | (a) | | 71.50 | | | | - | | | - |
09/01/10 – 09/30/10 | | | - | | | - | | | | - | | | - |
Period | | Total Number of Shares Purchased | | Average Price Paid per Share | | | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | | Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs | |
01/01/11 – 01/31/11 | | | 102 | (a) | $ | 75.00 | | | | - | | $ | - | |
02/01/11 – 02/28/11 | | | - | | | - | | | | - | | | - | |
03/01/11 – 03/31/11 | | | - | | | - | | | | - | | | - | |
(a) | APCo purchased 3102 shares of its 4.50% cumulative preferred stock and I&M purchased 3 shares of its 4.125% cumulative preferred stock in a privately-negotiated transactionstransaction outside of an announced program. |
Item 5. Other Information
NONE
Item 6. Exhibits
AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo
12 – Computation of Consolidated Ratio of Earnings to Fixed Charges.
AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo
31(a) – Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31(b) – Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
AEP, APCo, CSPCo, I&M, OPCo, PSO and SWEPCo
32(a) – Certification of Chief Executive Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
32(b) – Certification of Chief Financial Officer Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: /s/Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer
APPALACHIAN POWER COMPANY
COLUMBUS SOUTHERN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY
��By: /s/Joseph M. Buonaiuto
Joseph M. Buonaiuto
Controller and Chief Accounting Officer
Date: November 1, 2010May 3, 2011