The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of the Cook Plant. The most recent decommissioning cost study was performed in 2009. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste ranges from $831 million to $1.5 billion in 2009 nondiscounted dollars. The wide range in estimated costs is caused by variables in assumptions. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amount recovered in rates was $14 million in 2010, $16 million in 2009 and $27 million in 2008. Reduced annual decommissioning cost recovery amounts reflect the units’ longer estima ted life and operating licenses granted by the NRC. Decommissioning costs recovered from customers are deposited in external trusts.
At December 31, 2010 and 2009, the total decommissioning trust fund balance was $1.2 billion and $1.1 billion, respectively. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability.
I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future net income, cash flows and possibly financial condition would be adversely affected if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered.
The Federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWH for fuel consumed after April 6, 1983 at the Cook Plant is being collected from customers and remitted to the U.S. Treasury. At December 31, 2010 and 2009, fees and related interest of $265 million and $265 million, respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $307 million and $306 million, respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program.
See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts.
I&M carries insurance coverage for property damage, decommissioning and decontamination at the Cook Plant in the amount of $1.8 billion. I&M purchases $1 billion of excess coverage for property damage, decommissioning and decontamination. Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes an industry mutual insurer for the placement of this insurance coverage. Participation in this mutual insurance requires a contingent financial obligation of up to $41 million for I&M which is assessable if the insurer’s financial resources would be inadequate to pay for losses.
The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public liability arising from a nuclear incident at $12.6 billion and covers any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $375 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $117.5 million on each licensed reactor in the U.S. payable in annual installments of $17.5 million. As a result, I&M could be assessed $235 million per nuclear incident payable in annual installments of $35 million. The number of incidents for which payments could be required is not limited.
In the event of an incident of a catastrophic nature, I&M is initially covered for the first $375 million through commercially available insurance. The next level of liability coverage of up to $12.2 billion would be covered by claims made under the Price-Anderson Act. If the liability were in excess of amounts recoverable from insurance and retrospective claim payments made under the Price-Anderson Act, I&M would seek to recover those amounts from customers through rate increases. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, net income, cash flows and financial condition could be adversely affected.
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. As of December 31, 2010, we recorded $46 million in Prepayments and Other Current Assets on our Consolidated Balance Sheets representing estimated recoverable amounts under the property insurance policy. Through December 31, 2010, 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. The treatment of the remaining accidental outage policy revenues through fuel clauses is discussed in “I&M Rate Matters” section of Note 4. 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 proceeding s are adverse, it could have an adverse impact on net income, cash flows and financial condition.
OPERATIONAL CONTINGENCIES
Insurance and Potential Losses
We maintain insurance coverage normal and customary for an integrated electric utility, subject to various deductibles. Our insurance includes coverage for all risks of physical loss or damage to our nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. Our insurance programs also generally provide coverage against loss arising from certain claims made by third parties and are in excess of retentions absorbed by us. Coverage is generally provided by a combination of our protected cell of EIS and/or various industry mutual and/or commercial insurance carriers.
See “Nuclear Contingencies” section of this footnote for a discussion of nuclear exposures and related insurance.
Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could have a material adverse effect on our net income, cash flows and financial condition.
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.
I&M and Fort Wayne reached a settlement agreement. The agreement, signed in October 2010, is subject to approval by the IURC. I&M filed a petition with the IURC seeking approval. 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 rates of the payments made to Fort Wayne. If the agreement is not approved by 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. After the Enron bankruptcy, the BOA Syndicate informed HPL of a purported default by Enron under the terms of the financing arrangement. This dispute was being litigated in federal courts in Texas and New York.
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. In May 2009, the judge awarded $20 million of attorneys’ fees to BOA. In October 2010, the Court of Appeals affirmed the New York district court’s decision as to the final judgment of $346 million plus interest 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 and 30 BCF of working gas 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 indemnified the buyer of HPL against any damages up to the 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 $448 million at December 31, 2010 and is included in Current Liabilities – Deferred Gain and Accrued Litigation Costs on the Consolidated Balance Sheet. $441 million related to this matter was included in Deferred Credits and Other Noncurrent Liabilities on our Consolidated Balance Sheet at December 31, 2009. The effect of this decision had no impact on consolidated net income for 2010.
In February 2011, we reached a settlement with BOA covering claims in both the New York and Texas proceedings and paid BOA $425 million. The settlement covers all claims with BOA and Enron. We received title to the 55 BCF of natural gas in the Bammel storage facility as part of the settlement. We do not expect the effect of the settlement to have a material impact on our 2011 consolidated net income.
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. We will continue to defend each remaining case where an AEP company is a defendant. We believe the remaining exposure is immaterial.
7. ACQUISITIONS, DISPOSITIONS AND DISCONTINUED OPERATIONS
ACQUISITIONS
2010
Valley Electric Membership Corporation (Utility Operations segment)
In November 2009, SWEPCo signed a letter of intent to purchase certain transmission and distribution assets of Valley Electric Membership Corporation (VEMCO). In October 2010, SWEPCo finalized the purchase for approximately $102 million and began serving VEMCO’s 30,000 customers in Louisiana.
2009
Oxbow Lignite Company and Red River Mining Company (Utility Operations segment)
On December 29, 2009, SWEPCo purchased 50% of the Oxbow Lignite Company, LLC (OLC) membership interest for $13 million. CLECO acquired the remaining 50% membership interest in the OLC for $13 million. The Oxbow Mine is located near Coushatta, Louisiana and will be used as one of the fuel sources for SWEPCo’s and CLECO’s jointly-owned Dolet Hills Generating Station. SWEPCo will account for OLC as an equity investment. Also, on December 29, 2009, DHLC purchased mining equipment and assets for $16 million from the Red River Mining Company.
2008
Erlbacher companies (AEP River Operations segment)
In June 2008, AEP River Operations purchased certain barging assets from Missouri Barge Line Company, Missouri Dry Dock and Repair Company and Cape Girardeau Fleeting, Inc. (collectively known as Erlbacher companies) for $35 million. These assets were incorporated into AEP River Operations’ business which will diversify its customer base.
DISPOSITIONS
2010
Electric Transmission Texas LLC (ETT) (Utility Operations segment)
TCC and TNC sold, at cost, $66 million and $73 million, respectively, of transmission facilities to ETT for the year ended December 31, 2010.
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 Consolidated Statements of Income for the year ended December 31, 2010.
2009
Electric Transmission Texas LLC (ETT) (Utility Operations segment)
In 2009, TCC and TNC sold, at cost, $93 million and $2 million, respectively, of transmission facilities to ETT.
2008
None
DISCONTINUED OPERATIONS
Management periodically assesses our overall business model and makes decisions regarding our continued support and funding of our various businesses and operations. When it is determined that we will seek to exit a particular business or activity and we have met the accounting requirements for reclassification, we will reclassify those businesses or activities as discontinued operations. The assets and liabilities of these discontinued operations are classified in Assets Held for Sale and Liabilities Held for Sale until the time that they are sold.
Certain of our operations were discontinued in 2008. Results of operations of these businesses are classified as shown in the following table:
| | | U.K. | |
| | | Generation (a) | |
| | | (in millions) |
| 2010 Revenue | | $ | - | |
| 2010 Pretax Income | | | - | |
| 2010 Earnings, Net of Tax | | | - | |
| | | | | |
| 2009 Revenue | | $ | - | |
| 2009 Pretax Income | | | - | |
| 2009 Earnings, Net of Tax | | | - | |
| | | | | |
| 2008 Revenue | | $ | 2 | |
| 2008 Pretax Income | | | 2 | |
| 2008 Earnings, Net of Tax | | | 12 | |
| (a) | The 2008 amounts relate primarily to favorable income tax reserve adjustments. |
8. BENEFIT PLANS
For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Investments Held in Trust for Future Liabilities” and “Fair Value Measurements of Assets and Liabilities” sections of Note 1.
We sponsor a qualified pension plan and two unfunded nonqualified pension plans. Substantially all of our employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. We sponsor OPEB plans to provide medical and life insurance benefits for retired employees.
We recognize the funded status associated with our defined benefit pension and OPEB plans in the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. We recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. We record a regulatory asset instead of other comprehensive income for qualifying benefit costs of our regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecog nized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Actuarial Assumptions for Benefit Obligations
The weighted-average assumptions as of December 31 of each year used in the measurement of our benefit obligations are shown in the following table:
| | | | | | | Other Postretirement |
| | | | Pension Plans | | | Benefit Plans |
| | Assumptions | | 2010 | | | 2009 | | | 2010 | | 2009 |
| | Discount Rate | | 5.05 | % | | | 5.60 | % | | | 5.25 | % | | 5.85 | % |
| | Rate of Compensation Increase | | 4.95 | % | (a) | | 4.60 | % | (a) | | N/A | | N/A |
| (a) | Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. |
N/A Not applicable
We use a duration-based method to determine the discount rate for our plans. A hypothetical portfolio of high quality corporate bonds similar to those included in the Moody’s Aa bond index is constructed with a duration matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.
For 2010, the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 11.5% per year, with an average increase of 4.95%.
Actuarial Assumptions for Net Periodic Benefit Costs
The weighted-average assumptions as of January 1 of each year used in the measurement of our benefit costs are shown in the following table:
| | | | | | | Other Postretirement |
| | | | | Pension Plans | | Benefit Plans |
| | | | 2010 | | 2009 | | 2008 | | 2010 | | 2009 | | 2008 |
| | Discount Rate | | 5.60 | % | | 6.00 | % | | 6.00 | % | | 5.85 | % | | 6.10 | % | | 6.20 | % |
| | Expected Return on Plan Assets | | 8.00 | % | | 8.00 | % | | 8.00 | % | | 8.00 | % | | 7.75 | % | | 8.00 | % |
| | Rate of Compensation Increase | | 4.60 | % | | 5.90 | % | | 5.90 | % | | N/A | | N/A | | N/A |
| | | | | | | | | | | | | | | | | | | | |
| | N/A Not Applicable | | | | | | | | | | | | | | | | | | |
The expected return on plan assets for 2010 was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation and current prospects for economic growth.
The health care trend rate assumptions as of January 1 of each year used for OPEB plans measurement purposes are shown below:
| | Health Care Trend Rates | | 2010 | | 2009 |
| | Initial | | 8.00 | % | | 6.50 | % |
| | Ultimate | | 5.00 | % | | 5.00 | % |
| | Year Ultimate Reached | | 2016 | | 2012 |
Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects:
| | | 1% Increase | | | 1% Decrease | |
| | | (in millions) | |
| Effect on Total Service and Interest Cost | | | | | | |
Components of Net Periodic Postretirement Health Care Benefit Cost | | $ | 22 | | | $ | (18 | ) |
| | | | | | | | | |
| Effect on the Health Care Component of the | | | | | | | | |
| Accumulated Postretirement Benefit Obligation | | | 255 | | | | (209 | ) |
Significant Concentrations of Risk within Plan Assets
In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. We monitor the plans to control security diversification and ensure compliance with our investment policy. At December 31, 2010, the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details.
Benefit Plan Obligations, Plan Assets and Funded Status as of December 31, 2010 and 2009
The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status as of December 31. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively.
| | | | | | Other Postretirement | |
| | | Pension Plans | | | Benefit Plans | |
| | | 2010 | | | 2009 | | | 2010 | | | 2009 | |
| Change in Benefit Obligation | | (in millions) | |
| Benefit Obligation at January 1 | | $ | 4,701 | | | $ | 4,301 | | | $ | 1,941 | | | $ | 1,843 | |
| Service Cost | | | 111 | | | | 104 | | | | 47 | | | | 42 | |
| Interest Cost | | | 253 | | | | 254 | | | | 113 | | | | 110 | |
| Actuarial Loss | | | 222 | | | | 290 | | | | 164 | | | | 32 | |
| Plan Amendment Prior Service Credit | | | - | | | | - | | | | (36 | ) | | | - | |
| Benefit Payments | | | (480 | ) | | | (248 | ) | | | (142 | ) | | | (120 | ) |
| Participant Contributions | | | - | | | | - | | | | 29 | | | | 25 | |
| Medicare Subsidy | | | - | | | | - | | | | 9 | | | | 9 | |
| Benefit Obligation at December 31 | | $ | 4,807 | | | $ | 4,701 | | | $ | 2,125 | | | $ | 1,941 | |
| | | | | | | | | | | | | | | | | |
| Change in Fair Value of Plan Assets | | | | | | | | | | | | | | | | |
| Fair Value of Plan Assets at January 1 | | $ | 3,403 | | | $ | 3,161 | | | $ | 1,308 | | | $ | 1,018 | |
| Actual Gain on Plan Assets | | | 420 | | | | 482 | | | | 149 | | | | 235 | |
| Company Contributions | | | 515 | | | | 8 | | | | 117 | | | | 150 | |
| Participant Contributions | | | - | | | | - | | | | 29 | | | | 25 | |
| Benefit Payments | | | (480 | ) | | | (248 | ) | | | (142 | ) | | | (120 | ) |
| Fair Value of Plan Assets at December 31 | | $ | 3,858 | | | $ | 3,403 | | | $ | 1,461 | | | $ | 1,308 | |
| | | | | | | | | | | | | | | | | |
| Underfunded Status at December 31 | | $ | (949 | ) | | $ | (1,298 | ) | | $ | (664 | ) | | $ | (633 | ) |
| Benefit Amounts Recognized on the Balance Sheets as of December 31, 2010 and 2009 | |
| | | | | | | | | | | | | |
| | | | Other Postretirement | |
| | Pension Plans | | Benefit Plans | |
| | December 31, | |
| | 2010 | | 2009 | | 2010 | | 2009 | |
| | (in millions) | |
| Other Current Liabilities - Accrued Short-term | | | | | | | | | | | | |
| Benefit Liability | | $ | (8 | ) | | $ | (10 | ) | | $ | (4 | ) | | $ | (4 | ) |
| Employee Benefits and Pension Obligations - | | | | | | | | | | | | | | | | |
| Accrued Long-term Benefit Liability | | | (941 | ) | | | (1,288 | ) | | | (660 | ) | | | (629 | ) |
| Underfunded Status | | $ | (949 | ) | | $ | (1,298 | ) | | $ | (664 | ) | | $ | (633 | ) |
| Amounts Included in AOCI and Regulatory Assets as of December 31, 2010 and 2009 |
| |
| | | | Other Postretirement |
| | Pension Plans | | Benefit Plans |
| | December 31, |
| | 2010 | | 2009 | | 2010 | | 2009 | |
| Components | (in millions) |
| Net Actuarial Loss | | $ | 2,129 | | | $ | 2,096 | | | $ | 638 | | | $ | 546 | |
| Prior Service Cost (Credit) | | | 11 | | | | 12 | | | | (20 | ) | | | 3 | |
| Transition Obligation | | | - | | | | - | | | | 3 | | | | 43 | |
| | | | | | | | | | | | | | | | | |
| Recorded as | | | | | | | | | | | | | | | | |
| Regulatory Assets | | $ | 1,764 | | | $ | 1,750 | | | $ | 388 | | | $ | 380 | |
| Deferred Income Taxes | | | 132 | | | | 125 | | | | 81 | | | | 74 | |
| Net of Tax AOCI | | | 244 | | | | 233 | | | | 152 | | | | 138 | |
Components of the change in amounts included in AOCI and Regulatory Assets during the years ended December 31, 2010 and 2009 are as follows:
| | | | Other Postretirement | |
| | Pension Plans | | Benefit Plans | |
| | Years Ended December 31, | |
| | 2010 | | 2009 | | 2010 | | 2009 | |
| Components | (in millions) | |
| Actuarial Loss (Gain) During the Year | | $ | 121 | | | $ | 130 | | | $ | 121 | | | $ | (127 | ) |
| Prior Service Credit | | | - | | | | - | | | | (36 | ) | | | - | |
| Amortization of Actuarial Loss | | | (89 | ) | | | (59 | ) | | | (29 | ) | | | (42 | ) |
| Amortization of Transition Obligation | | | - | | | | - | | | | (27 | ) | | | (27 | ) |
| Change for the Year | | $ | 32 | | | $ | 71 | | | $ | 29 | | | $ | (196 | ) |
Pension and Other Postretirement Plans’ Assets
The following table presents the classification of pension plan assets within the fair value hierarchy at December 31, 2010:
| | | | | | | | | | | | | | | | | | Year End | |
| Asset Class | | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | | | Allocation | |
| | | (in millions) | | | | |
| Equities: | | | | | | | | | | | | | | | | | | |
| Domestic | | $ | 1,350 | | | $ | 2 | | | $ | - | | | $ | - | | | $ | 1,352 | | | | 35.1 | % |
| International | | | 403 | | | | - | | | | - | | | | - | | | | 403 | | | | 10.4 | % |
| Real Estate Investment Trusts | | | 112 | | | | - | | | | - | | | | - | | | | 112 | | | | 2.9 | % |
| Common Collective Trust - | | | | | | | | | | | | | | | | | | | | | | | | |
| International | | | - | | | | 163 | | | | - | | | | - | | | | 163 | | | | 4.2 | % |
| Subtotal - Equities | | | 1,865 | | | | 165 | | | | - | | | | - | | | | 2,030 | | | | 52.6 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed Income: | | | | | | | | | | | | | | | | | | | | | | | | |
| United States Government and | | | | | | | | | | | | | | | | | | | | | | | | |
| Agency Securities | | | - | | | | 634 | | | | - | | | | - | | | | 634 | | | | 16.4 | % |
| Corporate Debt | | | - | | | | 672 | | | | - | | | | - | | | | 672 | | | | 17.4 | % |
| Foreign Debt | | | - | | | | 127 | | | | - | | | | - | | | | 127 | | | | 3.3 | % |
| State and Local Government | | | - | | | | 23 | | | | - | | | | - | | | | 23 | | | | 0.6 | % |
| Other - Asset Backed | | | - | | | | 51 | | | | - | | | | - | | | | 51 | | | | 1.3 | % |
| Subtotal - Fixed Income | | | - | | | | 1,507 | | | | - | | | | - | | | | 1,507 | | | | 39.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Real Estate | | | - | | | | - | | | | 83 | | | | - | | | | 83 | | | | 2.2 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Alternative Investments | | | - | | | | - | | | | 130 | | | | - | | | | 130 | | | | 3.4 | % |
| Securities Lending | | | - | | | | 254 | | | | - | | | | - | | | | 254 | | | | 6.6 | % |
| Securities Lending Collateral (a) | | | - | | | | - | | | | - | | | | (276 | ) | | | (276 | ) | | | (7.1 | ) % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash and Cash Equivalents (b) | | | - | | | | 127 | | | | - | | | | 2 | | | | 129 | | | | 3.3 | % |
| Other - Pending Transactions and | | | | | | | | | | | | | | | | | | | | | | | | |
| Accrued Income (c) | | | - | | | | - | | | | - | | | | 1 | | | | 1 | | | | - | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 1,865 | | | $ | 2,053 | | | $ | 213 | | | $ | (273 | ) | | $ | 3,858 | | | | 100.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) | Amounts in "Other" column primarily represent an obligation to repay cash collateral received as part of the Securities Lending Program. |
| (b) | Amounts in "Other" column primarily represent foreign currency holdings. |
| (c) | Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement. |
The following table sets forth a reconciliation of changes in the fair value of real estate and alternative investments classified as Level 3 in the fair value hierarchy for AEP’s pension assets:
| | | | | | Alternative | | | Total | |
| | | Real Estate | | | Investments | | | Level 3 | |
| | | (in millions) | |
| Balance as of January 1, 2010 | | $ | 90 | | | $ | 106 | | | $ | 196 | |
| Actual Return on Plan Assets | | | | | | | | | | | | |
| Relating to Assets Still Held as of the Reporting Date | | | (7 | ) | | | 4 | | | | (3 | ) |
| Relating to Assets Sold During the Period | | | - | | | | 1 | | | | 1 | |
| Purchases and Sales | | | - | | | | 19 | | | | 19 | |
| Transfers into Level 3 | | | - | | | | - | | | | - | |
| Transfers out of Level 3 | | | - | | | | - | | | | - | |
| Balance as of December 31, 2010 | | $ | 83 | | | $ | 130 | | | $ | 213 | |
The following table presents the classification of OPEB plan assets within the fair value hierarchy at December 31, 2010:
| | | | | | | | | | | | | | | | | | Year End | |
| Asset Class | | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | | | Allocation | |
| | | (in millions) | | | | |
| Equities: | | | | | | | | | | | | | | | | | | |
| Domestic | | $ | 584 | | | $ | - | | | $ | - | | | $ | - | | | $ | 584 | | | | 40.0 | % |
| International | | | 220 | | | | - | | | | - | | | | - | | | | 220 | | | | 15.1 | % |
| Common Collective Trust - | | | | | | | | | | | | | | | | | | | | | | | | |
| Global | | | - | | | | 115 | | | | - | | | | - | | | | 115 | | | | 7.9 | % |
| Subtotal - Equities | | | 804 | | | | 115 | | | | - | | | | - | | | | 919 | | | | 63.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed Income: | | | | | | | | | | | | | | | | | | | | | | | | |
| Common Collective Trust - Debt | | | - | | | | 48 | | | | - | | | | - | | | | 48 | | | | 3.3 | % |
| United States Government and | | | | | | | | | | | | | | | | | | | | | | | | |
| Agency Securities | | | - | | | | 93 | | | | - | | | | - | | | | 93 | | | | 6.4 | % |
| Corporate Debt | | | - | | | | 110 | | | | - | | | | - | | | | 110 | | | | 7.5 | % |
| Foreign Debt | | | - | | | | 25 | | | | - | | | | - | | | | 25 | | | | 1.7 | % |
| State and Local Government | | | - | | | | 3 | | | | - | | | | - | | | | 3 | | | | 0.2 | % |
| Other - Asset Backed | | | - | | | | 1 | | | | - | | | | - | | | | 1 | | | | 0.1 | % |
| Subtotal - Fixed Income | | | - | | | | 280 | | | | - | | | | - | | | | 280 | | | | 19.2 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Trust Owned Life Insurance: | | | | | | | | | | | | | | | | | | | | | | | | |
| International Equities | | | - | | | | 49 | | | | - | | | | - | | | | 49 | | | | 3.3 | % |
| United States Bonds | | | - | | | | 163 | | | | - | | | | - | | | | 163 | | | | 11.1 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash and Cash Equivalents (a) | | | 21 | | | | 25 | | | | - | | | | 1 | | | | 47 | | | | 3.2 | % |
| Other - Pending Transactions and | | | | | | | | | | | | | | | | | | | | | | | | |
| Accrued Income (b) | | | - | | | | - | | | | - | | | | 3 | | | | 3 | | | | 0.2 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 825 | | | $ | 632 | | | $ | - | | | $ | 4 | | | $ | 1,461 | | | | 100.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) | Amounts in "Other" column primarily represent foreign currency holdings. |
| (b) | Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement. |
The following table presents the classification of pension plan assets within the fair value hierarchy at December 31, 2009:
| | | | | | | | | | | | | | | | | | Year End | |
| Asset Class | | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | | | Allocation | |
| | | (in millions) | | | | |
| Equities: | | | | | | | | | | | | | | | | | | |
| Domestic | | $ | 1,219 | | | $ | - | | | $ | - | | | $ | - | | | $ | 1,219 | | | | 35.8 | % |
| International | | | 320 | | | | - | | | | - | | | | - | | | | 320 | | | | 9.4 | % |
| Real Estate Investment Trusts | | | 87 | | | | - | | | | - | | | | - | | | | 87 | | | | 2.6 | % |
| Common Collective Trust - | | | | | | | | | | | | | | | | | | | | | | | | |
| International | | | - | | | | 161 | | | | - | | | | - | | | | 161 | | | | 4.7 | % |
| Subtotal - Equities | | | 1,626 | | | | 161 | | | | - | | | | - | | | | 1,787 | | | | 52.5 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed Income: | | | | | | | | | | | | | | | | | | | | | | | | |
| United States Government and | | | | | | | | | | | | | | | | | | | | | | | | |
| Agency Securities | | | - | | | | 233 | | | | - | | | | - | | | | 233 | | | | 6.9 | % |
| Corporate Debt | | | - | | | | 831 | | | | - | | | | - | | | | 831 | | | | 24.4 | % |
| Foreign Debt | | | - | | | | 171 | | | | - | | | | - | | | | 171 | | | | 5.0 | % |
| State and Local Government | | | - | | | | 35 | | | | - | | | | - | | | | 35 | | | | 1.0 | % |
| Other - Asset Backed | | | - | | | | 27 | | | | - | | | | - | | | | 27 | | | | 0.8 | % |
| Subtotal - Fixed Income | | | - | | | | 1,297 | | | | - | | | | - | | | | 1,297 | | | | 38.1 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Real Estate | | | - | | | | - | | | | 90 | | | | - | | | | 90 | | | | 2.7 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Alternative Investments | | | - | | | | - | | | | 106 | | | | - | | | | 106 | | | | 3.1 | % |
| Securities Lending | | | - | | | | 173 | | | | - | | | | - | | | | 173 | | | | 5.1 | % |
| Securities Lending Collateral (a) | | | - | | | | - | | | | - | | | | (196 | ) | | | (196 | ) | | | (5.8 | ) % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash and Cash Equivalents (b) | | | - | | | | 116 | | | | - | | | | 4 | | | | 120 | | | | 3.5 | % |
| Other - Pending Transactions and | | | | | | | | | | | | | | | | | | | | | | | | |
| Accrued Income (c) | | | - | | | | - | | | | - | | | | 26 | | | | 26 | | | | 0.8 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 1,626 | | | $ | 1,747 | | | $ | 196 | | | $ | (166 | ) | | $ | 3,403 | | | | 100.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) | Amounts in "Other" column primarily represent an obligation to repay cash collateral received as part of the Securities Lending Program. |
| (b) | Amounts in "Other" column primarily represent foreign currency holdings. |
| (c) | Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement. |
The following table sets forth a reconciliation of changes in the fair value of real estate and alternative investments classified as Level 3 in the fair value hierarchy for the pension assets:
| | | | | | Alternative | | | Total | |
| | | Real Estate | | | Investments | | | Level 3 | |
| | | (in millions) | |
| Balance as of January 1, 2009 | | $ | 137 | | | $ | 106 | | | $ | 243 | |
| Actual Return on Plan Assets | | | | | | | | | | | | |
| Relating to Assets Still Held as of the Reporting Date | | | (47 | ) | | | (14 | ) | | | (61 | ) |
| Relating to Assets Sold During the Period | | | - | | | | 1 | | | | 1 | |
| Purchases and Sales | | | - | | | | 13 | | | | 13 | |
| Transfers in and/or out of Level 3 | | | - | | | | - | | | | - | |
| Balance as of December 31, 2009 | | $ | 90 | | | $ | 106 | | | $ | 196 | |
The following table presents the classification of OPEB plan assets within the fair value hierarchy at December 31, 2009:
| | | | | | | | | | | | | | | | | | Year End | |
| Asset Class | | Level 1 | | | Level 2 | | | Level 3 | | | Other | | | Total | | | Allocation | |
| | | (in millions) | |
| Equities: | | | | | | | | | | | | | | | | | | |
| Domestic | | $ | 343 | | | $ | - | | | $ | - | | | $ | - | | | $ | 343 | | | | 26.2 | % |
| International | | | 375 | | | | - | | | | - | | | | - | | | | 375 | | | | 28.7 | % |
| Common Collective Trust - | | | | | | | | | | | | | | | | | | | | | | | | |
| Global | | | - | | | | 93 | | | | - | | | | - | | | | 93 | | | | 7.1 | % |
| Subtotal - Equities | | | 718 | | | | 93 | | | | - | | | | - | | | | 811 | | | | 62.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Fixed Income: | | | | | | | | | | | | | | | | | | | | | | | | |
| Common Collective Trust - Debt | | | - | | | | 38 | | | | - | | | | - | | | | 38 | | | | 2.9 | % |
| United States Government and | | | | | | | | | | | | | | | | | | | | | | | | |
| Agency Securities | | | - | | | | 42 | | | | - | | | | - | | | | 42 | | | | 3.2 | % |
| Corporate Debt | | | - | | | | 141 | | | | - | | | | - | | | | 141 | | | | 10.8 | % |
| Foreign Debt | | | - | | | | 32 | | | | - | | | | - | | | | 32 | | | | 2.4 | % |
| State and Local Government | | | - | | | | 6 | | | | - | | | | - | | | | 6 | | | | 0.5 | % |
| Other - Asset Backed | | | - | | | | 2 | | | | - | | | | - | | | | 2 | | | | 0.2 | % |
| Subtotal - Fixed Income | | | - | | | | 261 | | | | - | | | | - | | | | 261 | | | | 20.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Trust Owned Life Insurance: | | | | | | | | | | | | | | | | | | | | | | | | |
| International Equities | | | - | | | | 75 | | | | - | | | | - | | | | 75 | | | | 5.7 | % |
| United States Bonds | | | - | | | | 131 | | | | - | | | | - | | | | 131 | | | | 10.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Cash and Cash Equivalents (a) | | | 7 | | | | 14 | | | | - | | | | 1 | | | | 22 | | | | 1.7 | % |
| Other - Pending Transactions and | | | | | | | | | | | | | | | | | | | | | | | | |
| Accrued Income (b) | | | - | | | | - | | | | - | | | | 8 | | | | 8 | | | | 0.6 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 725 | | | $ | 574 | | | $ | - | | | $ | 9 | | | $ | 1,308 | | | | 100.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) | Amounts in "Other" column primarily represent foreign currency holdings. |
| (b) | Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending settlement. |
Determination of Pension Expense
We base our determination of pension expense or income on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.
| | | December 31, | |
| Accumulated Benefit Obligation | | 2010 | | 2009 | |
| | | (in millions) | |
| Qualified Pension Plan | | | $ | 4,659 | | | $ | 4,539 | |
| Nonqualified Pension Plans | | | | 80 | | | | 90 | |
| Total | | | $ | 4,739 | | | $ | 4,629 | |
| | | | | | | | | | |
For our underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets of these plans at December 31, 2010 and 2009 were as follows:
| | Underfunded Pension Plans | |
| | December 31, | |
| | 2010 | | 2009 | |
| | (in millions) | |
| Projected Benefit Obligation | | $ | 4,807 | | | $ | 4,701 | |
| | | | | | | | | |
| Accumulated Benefit Obligation | | $ | 4,739 | | | $ | 4,629 | |
| Fair Value of Plan Assets | | | 3,858 | | | | 3,403 | |
| Underfunded Accumulated Benefit Obligation | | $ | (881 | ) | | $ | (1,226 | ) |
Estimated Future Benefit Payments and Contributions
We expect contributions and payments for the pension plans of $158 million and the OPEB plans of $86 million during 2011. The estimated pension benefit payments for the unfunded plan and contributions to the trust are at least the minimum amount required by ERISA plus payment of unfunded nonqualified benefits. For the qualified pension plan, we may make additional discretionary contributions to maintain the funded status of the plan. The contribution to the OPEB plans is generally based on the amount of the OPEB plans’ periodic benefit costs for accounting purposes as provided in agreements with state regulatory authorities, plus the additional discretionary contribution of our Medicare subsidy receipts.
The table below reflects the total benefits expected to be paid from the plan or from our assets, including both our share of the benefit cost and the participants’ share of the cost, which is funded by participant contributions to the plan. Medicare subsidy receipts are shown in the year of the corresponding benefit payments, even though actual cash receipts are expected early in the following year. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for pension benefits and OPEB are as fol lows:
| | Pension Plans | | Other Postretirement Benefit Plans | |
| | Pension | | Benefit | | Medicare Subsidy | |
| | Payments | | Payments | | Receipts | |
| | (in millions) | |
| 2011 | | $ | 314 | | | $ | 143 | | | $ | 11 | |
| 2012 | | | 320 | | | | 148 | | | | 12 | |
| 2013 | | | 325 | | | | 153 | | | | 13 | |
| 2014 | | | 333 | | | | 160 | | | | 14 | |
| 2015 | | | 342 | | | | 166 | | | | 15 | |
| Years 2016 to 2020, in Total | | | 1,811 | | | | 931 | | | | 95 | |
Components of Net Periodic Benefit Cost
The following table provides the components of our net periodic benefit cost for the plans for the years ended December 31, 2010, 2009 and 2008:
| | | | | | | Other Postretirement |
| | | | Pension Plans | | Benefit Plans |
| | | | | Years Ended December 31, |
| | | | | 2010 | | 2009 | | 2008 | | 2010 | | 2009 | | 2008 |
| | | | | (in millions) |
| | Service Cost | | $ | 111 | | $ | 104 | | $ | 100 | | $ | 47 | | $ | 42 | | $ | 42 |
| | Interest Cost | | | 253 | | | 254 | | | 249 | | | 113 | | | 110 | | | 113 |
| | Expected Return on Plan Assets | | | (312) | | | (321) | | | (336) | | | (105) | | | (80) | | | (111) |
| | Amortization of Transition Obligation | | | - | | | - | | | - | | | 27 | | | 27 | | | 27 |
| | Amortization of Prior Service Cost | | | - | | | - | | | 1 | | | - | | | - | | | - |
| | Amortization of Net Actuarial Loss | | | 89 | | | 59 | | | 37 | | | 29 | | | 42 | | | 9 |
| | Net Periodic Benefit Cost | | | 141 | | | 96 | | | 51 | | | 111 | | | 141 | | | 80 |
| | Capitalized Portion | | | (44) | | | (30) | | | (16) | | | (35) | | | (44) | | | (25) |
| | Net Periodic Benefit Cost Recognized as Expense | | $ | 97 | | $ | 66 | | $ | 35 | | $ | 76 | | $ | 97 | | $ | 55 |
Estimated amounts expected to be amortized to net periodic benefit costs and the impact on the balance sheet during 2011 are shown in the following table:
| | | | | | Other | |
| | | | | | Postretirement | |
| | | Pension Plans | | | Benefit Plans | |
| Components | | (in millions) | |
| Net Actuarial Loss | | $ | 121 | | | $ | 33 | |
| Prior Service Cost (Credit) | | | 1 | | | | (2 | ) |
| Transition Obligation | | | - | | | | 2 | |
| Total Estimated 2011 Amortization | | $ | 122 | | | $ | 33 | |
| | | | | | | | | |
| Expected to be Recorded as | | | | | | | | |
| Regulatory Asset | | $ | 99 | | | $ | 19 | |
| Deferred Income Taxes | | | 8 | | | | 5 | |
| Net of Tax AOCI | | | 15 | | | | 9 | |
| Total | | $ | 122 | | | $ | 33 | |
American Electric Power System Retirement Savings Plan
We sponsor the American Electric Power System Retirement Savings Plan, a defined contribution retirement savings plan for substantially all employees who are not members of the United Mine Workers of America (UMWA). It is a qualified plan offering participants an opportunity to contribute a portion of their pay with features under Section 401(k) of the Internal Revenue Code. We provided matching contributions of 75% of the first 6% of eligible compensation contributed by an employee in 2008. Effective January 1, 2009, we match the first 1% of eligible employee contributions at 100% and the next 5% of contributions at 70%. The cost for company matching contributions totaled $61 million in 2010, $74 million in 2009 and $71 million in 2008.
UMWA Benefits
We provide UMWA pension, health and welfare benefits for certain unionized mining employees, retirees and their survivors who meet eligibility requirements. UMWA trustees make final interpretive determinations with regard to all benefits. The pension benefits are administered by UMWA trustees and contributions are made to their trust funds. The health and welfare benefits are administered by us and benefits are paid from our general assets. Contributions and benefits paid were not material in 2010, 2009 and 2008.
9. BUSINESS SEGMENTS
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 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.
· Electricity transmission and distribution in the U.S.
AEP River Operations
| · | Commercial barging operations that annually transport approximately 39 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers. Approximately 46% of the barging is for transportation of agricultural products, 25% for coal, 11% for steel and 18% for other commodities. |
Generation and Marketing
| · | 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. |
| · | Tax and interest expense adjustments related to our UK operations which were sold in 2004 and 2002. |
| · | 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 expire in 2011. |
| · | The 2008 cash settlement of a purchase power and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in 2006. |
| · | Revenue sharing related to the Plaquemine Cogeneration Facility. |
The tables below present our reportable segment information for years ended December 31, 2010, 2009 and 2008 and balance sheet information as of December 31, 2010 and 2009. These amounts include certain estimates and allocations where necessary.
| | | | | | Nonutility Operations | | | | | | | | | |
| | | | | | | | | Generation | | | | | | | | | |
| | Utility | | AEP River | | and | | All Other | Reconciling | | |
| | Operations | | Operations | | Marketing | | (a) | Adjustments | Consolidated |
| | | (in millions) |
| Year Ended December 31, 2010 | | | | | | | | | | | | | | | | | | |
| Revenues from: | | | | | | | | | | | | | | | | | | |
| External Customers | | $ | 13,687 | | $ | 566 | | $ | 173 | | $ | 1 | | $ | - | | $ | 14,427 |
| Other Operating Segments | | | 104 | | | 22 | | | - | | | 14 | | | (140) | | | - |
| Total Revenues | | $ | 13,791 | | $ | 588 | | $ | 173 | | $ | 15 | | $ | (140) | | $ | 14,427 |
| | | | | | | | | | | | | | | | | | | |
| Depreciation and Amortization | | $ | 1,598 | | $ | 24 | | $ | 30 | | $ | 2 | | $ | (13) | (b) | $ | 1,641 |
| Interest Income | | | 8 | | | - | | | 2 | | | 31 | | | (20) | | | 21 |
| Interest Expense | | | 942 | | | 14 | | | 20 | | | 58 | | | (35) | (b) | | 999 |
| Income Tax Expense (Credit) | | | 650 | | | 19 | | | (20) | | | (6) | | | - | | | 643 |
| | | | | | | | | | | | | | | | | | | |
| Net Income (Loss) | | | 1,201 | | | 37 | | | 25 | | | (45) | | | - | | | 1,218 |
| | | | | | | | | | | | | | | | | | | |
| Gross Property Additions | | | 2,475 | | | 23 | | | 1 | | | 1 | | | - | | | 2,500 |
| | | | | | | | | | | | | | | | | | | |
| | | | | | Nonutility Operations | | | | | | | | | |
| | | | | | | | | Generation | | | | | | | | | |
| | Utility | | AEP River | | and | | All Other | Reconciling | | |
| | Operations | | Operations | | Marketing | | (a) | Adjustments | Consolidated |
| | | (in millions) |
| Year Ended December 31, 2009 | | | | | | | | | | | | | | | | | | |
| Revenues from: | | | | | | | | | | | | | | | | | | |
| External Customers | | $ | 12,733 | (e) | $ | 490 | | $ | 281 | | $ | (15) | | $ | - | | $ | 13,489 |
| Other Operating Segments | | | 70 | (e) | | 18 | | | 5 | | | 36 | | | (129) | | | - |
| Total Revenues | | $ | 12,803 | | $ | 508 | | $ | 286 | | $ | 21 | | $ | (129) | | $ | 13,489 |
| | | | | | | | | | | | | | | | | | | |
| Depreciation and Amortization | | $ | 1,561 | | $ | 17 | | $ | 29 | | $ | 2 | | $ | (12) | (b) | $ | 1,597 |
| Interest Income | | | 4 | | | - | | | - | | | 47 | | | (40) | | | 11 |
| Interest Expense | | | 916 | | | 5 | | | 21 | | | 86 | | | (55) | (b) | | 973 |
| Income Tax Expense (Credit) | | | 553 | | | 23 | | | - | | | (1) | | | - | | | 575 |
| | | | | | | | | | | | | | | | | | | |
| Income (Loss) Before Discontinued | | | | | | | | | | | | | | | | | | |
| Operations and Extraordinary Loss | | $ | 1,329 | | $ | 47 | | $ | 41 | | $ | (47) | | $ | - | | $ | 1,370 |
| Extraordinary Loss, Net of Tax | | | (5) | | | - | | | - | | | - | | | - | | | (5) |
| Net Income (Loss) | | $ | 1,324 | | $ | 47 | | $ | 41 | | $ | (47) | | $ | - | | $ | 1,365 |
| | | | | | | | | | | | | | | | | | | |
| Gross Property Additions | | $ | 2,813 | | $ | 81 | | $ | 1 | | $ | 1 | | $ | - | | $ | 2,896 |
| | | | | | | | | | | | | | | | | | | |
| | | | | | Nonutility Operations | | | | | | | | | |
| | | | | | | | | Generation | | | | | | | | | |
| | Utility | | AEP River | | and | | All Other | Reconciling | | |
| | Operations | | Operations | | Marketing | | (a) | Adjustments | Consolidated |
| | | (in millions) |
| Year Ended December 31, 2008 | | | | | | | | | | | | | | | | | | |
| Revenues from: | | | | | | | | | | | | | | | | | | |
| External Customers | | $ | 13,326 | (e) | $ | 616 | | $ | 485 | | $ | 13 | | $ | - | | $ | 14,440 |
| Other Operating Segments | | | 240 | (e) | | 30 | | | (122) | | | 9 | | | (157) | | | - |
| Total Revenues | | $ | 13,566 | | $ | 646 | | $ | 363 | | $ | 22 | | $ | (157) | | $ | 14,440 |
| | | | | | | | | | | | | | | | | | | |
| Depreciation and Amortization | | $ | 1,450 | | $ | 14 | | $ | 28 | | $ | 2 | | $ | (11) | (b) | $ | 1,483 |
| Interest Income | | | 42 | | | - | | | 1 | | | 78 | | | (65) | | | 56 |
| Interest Expense | | | 915 | | | 5 | | | 22 | | | 94 | | | (79) | (b) | | 957 |
| Income Tax Expense | | | 515 | | | 26 | | | 17 | | | 84 | | | - | | | 642 |
| | | | | | | | | | | | | | | | | | | |
| Income Before Discontinued | | | | | | | | | | | | | | | | | | |
| Operations and Extraordinary Loss | | $ | 1,123 | | $ | 55 | | $ | 65 | | $ | 133 | | $ | - | | $ | 1,376 |
| Discontinued Operations, Net of Tax | | | - | | | - | | | - | | | 12 | | | - | | | 12 |
| Net Income | | $ | 1,123 | | $ | 55 | | $ | 65 | | $ | 145 | | $ | - | | $ | 1,388 |
| | | | | | | | | | | | | | | | | | | |
| Gross Property Additions | | $ | 3,871 | | $ | 116 | | $ | 2 | | $ | (29) | (c) | $ | - | | $ | 3,960 |
| | | | | | | | Nonutility Operations | | | | | | | | | | |
| | | | | | | | | | | Generation | | | | | Reconciling | | | | |
| | | | Utility | | AEP River | | and | | All Other | | Adjustments | | | | |
| | | | Operations | | Operations | | Marketing | | (a) | | (b) | | | Consolidated |
| | | | | (in millions) |
| December 31, 2010 | | | | | | | | | | | | | | | | | | | |
| Total Property, Plant and Equipment | | $ | 52,822 | | $ | 574 | | $ | 584 | | $ | 11 | | $ | (251) | | | $ | 53,740 |
| Accumulated Depreciation and Amortization | | | 17,795 | | | 110 | | | 198 | | | 9 | | | (46) | | | | 18,066 |
| Total Property, Plant and Equipment - Net | | $ | 35,027 | | $ | 464 | | $ | 386 | | $ | 2 | | $ | (205) | | | $ | 35,674 |
| | | | | | | | | | | | | | | | | | | | | | |
| Total Assets | | $ | 48,780 | | $ | 621 | | $ | 881 | | $ | 15,942 | | $ | (15,769) | (d) | | $ | 50,455 |
| | | | | | | | | | | | | | | | | | | | | | |
| Investments in Equity Method Investees | | | 157 | | | 3 | | | - | | | - | | | - | | | | 160 |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | Nonutility Operations | | | | | | | | | | |
| | | | | | | | | | | Generation | | | | | Reconciling | | | | |
| | | | Utility | | AEP River | | and | | All Other | | Adjustments | | | | |
| | | | Operations | | Operations | | Marketing | | (a) | | (b) | | | Consolidated |
| | | | | (in millions) |
| December 31, 2009 | | | | | | | | | | | | | | | | | | | |
| Total Property, Plant and Equipment | | $ | 50,905 | | $ | 436 | | $ | 571 | | $ | 10 | | $ | (238) | | | $ | 51,684 |
| Accumulated Depreciation and Amortization | | | 17,110 | | | 88 | | | 168 | | | 8 | | | (34) | | | | 17,340 |
| Total Property, Plant and Equipment - Net | | $ | 33,795 | | $ | 348 | | $ | 403 | | $ | 2 | | $ | (204) | | | $ | 34,344 |
| | | | | | | | | | | | | | | | | | | | | | |
| Total Assets | | $ | 46,930 | | $ | 495 | | $ | 779 | | $ | 15,094 | | $ | (14,950) | (d) | | $ | 48,348 |
| | | | | | | | | | | | | | | | | | | | | | |
| Investments in Equity Method Investees | | | 84 | | | 4 | | | - | | | - | | | - | | | | 88 |
| · | Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense, and other nonallocated costs. |
| · | Tax and interest expense adjustments related to our UK operations which were sold in 2004 and 2002. |
| · | 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 expire in 2011. |
| · | The 2008 cash settlement of a purchase power and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in 2006. The cash settlement of $255 million ($164 million, net of tax) is included in Net Income. |
| · | Revenue sharing related to the Plaquemine Cogeneration Facility. |
| (b) | Includes eliminations due to an intercompany capital lease. |
| (c) | Gross Property Additions for All Other includes construction expenditures of $8 million in 2008 related to the acquisition of turbines by one of our nonregulated, wholly-owned subsidiaries. These turbines were refurbished and transferred to a generating facility within our Utility Operations segment in the fourth quarter of 2008. The transfer of these turbines resulted in the elimination of $37 million from All Other and the addition of $37 million to Utility Operations. |
| (d) | 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. |
| (e) | 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 $(5) million and $122 million for the years ended December 31, 2009 and 2008, 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 SWEPCo with AE PEP ended in December 2009. |
10. 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 determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors.
The following table represents the gross notional volume of our outstanding derivative contracts as of December 31, 2010 and 2009:
| Notional Volume of Derivative Instruments |
| | | | | | | | |
| | Volume | | |
| | | December 31, | | Unit of |
| | | 2010 | | | 2009 | | Measure |
| | (in millions) | | |
| Commodity: | | | | | | | |
| Power | | | 652 | | | | 589 | | MWHs |
| Coal | | | 63 | | | | 60 | | Tons |
| Natural Gas | | | 94 | | | | 127 | | MMBtus |
| Heating Oil and Gasoline | | | 6 | | | | 6 | | Gallons |
| Interest Rate | | $ | 171 | | | $ | 216 | | USD |
| | | | | | | | | | |
| Interest Rate and Foreign Currency | | $ | 907 | | | $ | 83 | | 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. 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 |
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 nsus 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 December 31, 2010 and 2009 balance sheets, we netted $8 million and $12 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $109 million and $98 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 Consolidated Balance Sheets as of December 31, 2010 and 2009:
| Fair Value of Derivative Instruments | |
| December 31, 2010 | |
| | |
| | | Risk Management | | | | | | | | | |
| | | Contracts | | Hedging Contracts | | | | | |
| | | | | | | Interest Rate | | | | | |
| | | | | | | and Foreign | | Other | | | |
| Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Currency (a)(c) | | (a) (b) | | Total | |
| | | (in millions) | |
| Current Risk Management Assets | | | $ | 1,023 | | | $ | 18 | | | $ | 30 | | | $ | (839 | ) | | $ | 232 | |
| Long-term Risk Management Assets | | | | 546 | | | | 12 | | | | 2 | | | | (150 | ) | | | 410 | |
| Total Assets | | | | 1,569 | | | | 30 | | | | 32 | | | | (989 | ) | | | 642 | |
| | | | | | | | | | | | | | | | | | | | | | |
| Current Risk Management Liabilities | | | | 995 | | | | 13 | | | | 2 | | | | (881 | ) | | | 129 | |
| Long-term Risk Management Liabilities | | | | 387 | | | | 6 | | | | 3 | | | | (255 | ) | | | 141 | |
| Total Liabilities | | | | 1,382 | | | | 19 | | | | 5 | | | | (1,136 | ) | | | 270 | |
| | | | | | | | | | | | | | | | | | | | | | |
| Total MTM Derivative Contract Net Assets | | | | | | | | | | | | | | | | | | | | | |
| (Liabilities) | | | $ | 187 | | | $ | 11 | | | $ | 27 | | | $ | 147 | | | $ | 372 | |
| | | | | | | | | | | | | | | | | | | | | | |
| Fair Value of Derivative Instruments | |
| December 31, 2009 | |
| | |
| | | Risk Management | | | | | | | | | | | | | | | | | |
| | | Contracts | | Hedging Contracts | | | | | | | | | |
| | | | | | | | | | | Interest Rate | | | | | | | | | |
| | | | | | | | | | | and Foreign | | Other | | | | | |
| Balance Sheet Location | | Commodity (a) | | Commodity (a) | | Currency (a) | | (a) (b) | | Total | |
| | | (in millions) | |
| Current Risk Management Assets | | | $ | 1,078 | | | $ | 13 | | | $ | - | | | $ | (831 | ) | | $ | 260 | |
| Long-term Risk Management Assets | | | | 614 | | | | - | | | | - | | | | (271 | ) | | | 343 | |
| Total Assets | | | | 1,692 | | | | 13 | | | | - | | | | (1,102 | ) | | | 603 | |
| | | | | | | | | | | | | | | | | | | | | | |
| Current Risk Management Liabilities | | | | 997 | | | | 17 | | | | 3 | | | | (897 | ) | | | 120 | |
| Long-term Risk Management Liabilities | | | | 442 | | | | - | | | | 2 | | | | (316 | ) | | | 128 | |
| Total Liabilities | | | | 1,439 | | | | 17 | | | | 5 | | | | (1,213 | ) | | | 248 | |
| | | | | | | | | | | | | | | | | | | | | | |
| Total MTM Derivative Contract Net Assets | | | | | | | | | | | | | | | | | | | | | |
| (Liabilities) | | | $ | 253 | | | $ | (4 | ) | | $ | (5 | ) | | $ | 111 | | | $ | 355 | |
| | (a) | Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the Consolidated Balance Sheet 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. |
| | (c) | At December 31, 2010, Risk Management Assets included $7 million and Risk Management Liabilities included $1 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 years ended December 31, 2010 and 2009:
| Amount of Gain (Loss) Recognized on | |
| Risk Management Contracts | |
| | | Years Ended December 31, | |
| Location of Gain (Loss) | | 2010 | | 2009 | |
| | | (in millions) | |
| Utility Operations Revenue | | | $ | 85 | | | $ | 144 | |
| Other Revenue | | | | 9 | | | | 19 | |
| Regulatory Assets (a) | | | | (9 | ) | | | (28 | ) |
| Regulatory Liabilities (a) | | | | 38 | | | | (7 | ) |
| Total Gain (Loss) on Risk Management Contracts | | | $ | 123 | | | $ | 128 | |
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent 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 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 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 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 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 Consolidated Statements of Income. During 2010, we recognized gains of $6 million on our hedging instruments, offsetting losses of $6 million on our long-term debt and an immaterial amount of hedge ineffectiveness. During 2009, we did not employ any fair value hedging strategies. During 2008, we employed fair value hedging strategies and recognized an immaterial loss and no hedge ineffectiveness.
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 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 Consolidated Statements of Income, or in Regulatory Assets or Regulatory Liabilities on our Consolidated Balance Sheets, depending on the specific nature of the risk being hedged. During 2010, 2009 and 2008, 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 Consolidated Balance Sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our Consolidated Statements of Income. During 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 2010, 2009 and 2008, 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 Consolidated Balance Sheets into Depreciation and Amortization expense on our Consolidated Statements of Income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During 2010, 2009 and 2008, we designated foreign currency derivatives as cash flow hedges.
During 2009, we recognized a $6 million gain in Interest Expense related to hedge ineffectiveness on interest rate derivatives designated in cash flow hedge strategies. During 2010, 2009 and 2008, hedge ineffectiveness was immaterial or nonexistent for all of the other hedge strategies disclosed above.
The following tables provide details on designated, effective cash flow hedges included in AOCI on our Consolidated Balance Sheets and the reasons for changes in cash flow hedges for the years ended December 31, 2010 and 2009. All amounts in the following tables are presented net of related income taxes.
| Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | |
| Year Ended December 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 | | | 9 | | | | 13 | | | | 22 | |
| Amount of (Gain) or Loss Reclassified from AOCI | | | | | | | | | | | | |
| to Income Statement/within Balance Sheet: | | | | | | | | | | | | |
| Utility Operations Revenue | | | - | | | | - | | | | - | |
| Other Revenue | | | (7 | ) | | | - | | | | (7 | ) |
| Purchased Electricity for Resale | | | 4 | | | | - | | | | 4 | |
| Interest Expense | | | - | | | | 4 | | | | 4 | |
| Regulatory Assets (a) | | | 3 | | | | - | | | | 3 | |
| Regulatory Liabilities (a) | | | - | | | | - | | | | - | |
| Balance in AOCI as of December 31, 2010 | | $ | 7 | | | $ | 4 | | | $ | 11 | |
| | | | | | | | | | | | | |
| Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | |
| Year Ended December 31, 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 | | | (6 | ) | | | 11 | | | | 5 | |
| Amount of (Gain) or Loss Reclassified from AOCI | | | | | | | | | | | | |
| to Income Statement/within Balance Sheet: | | | | | | | | | | | | |
| Utility Operations Revenue | | | (15 | ) | | | - | | | | (15 | ) |
| Other Revenue | | | (15 | ) | | | - | | | | (15 | ) |
| Purchased Electricity for Resale | | | 29 | | | | - | | | | 29 | |
| Interest Expense | | | - | | | | 5 | | | | 5 | |
| Regulatory Assets (a) | | | 5 | | | | - | | | | 5 | |
| Regulatory Liabilities (a) | | | (7 | ) | | | - | | | | (7 | ) |
| Balance in AOCI as of December 31, 2009 | | $ | (2 | ) | | $ | (13 | ) | | $ | (15 | ) |
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
During 2008 we reclassified $7 million of gains from AOCI to net income.
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our Consolidated Balance Sheets at December 31, 2010 and 2009 were:
| Impact of Cash Flow Hedges on our Consolidated Balance Sheet | |
| December 31, 2010 | |
| | | | | | | | | | |
| | | | | Interest Rate | | | | |
| | | | | and Foreign | | | | |
| | Commodity | | Currency | | Total | |
| | (in millions) | |
| Hedging Assets (a) | | $ | 13 | | | $ | 25 | | | $ | 38 | |
| Hedging Liabilities (a) | | | (2 | ) | | | (4 | ) | | | (6 | ) |
| AOCI Gain (Loss) Net of Tax | | | 7 | | | | 4 | | | | 11 | |
| | | | | | | | | | | | | |
| Portion Expected to be Reclassified to Net | | | | | | | | | | | | |
| Income During the Next Twelve Months | | | 3 | | | | (2 | ) | | | 1 | |
| | | | | | | | | | | | | |
| Impact of Cash Flow Hedges on our Consolidated Balance Sheet | |
| December 31, 2009 | |
| | | | | | | | | | | | | |
| | | | | | Interest Rate | | | | | |
| | | | | | and Foreign | | | | | |
| | Commodity | | Currency | | Total | |
| | (in millions) | |
| Hedging Assets (a) | | $ | 8 | | | $ | - | | | $ | 8 | |
| Hedging Liabilities (a) | | | (12 | ) | | | (5 | ) | | | (17 | ) |
| AOCI Gain (Loss) Net of Tax | | | (2 | ) | | | (13 | ) | | | (15 | ) |
| | | | | | | | | | | | | |
| Portion Expected to be Reclassified to Net | | | | | | | | | | | | |
| Income During the Next Twelve Months | | | (2 | ) | | | (4 | ) | | | (6 | ) |
| (a) | Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on our 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 December 31, 2010, 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 41 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 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 represents: (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 December 31, 2010 and 2009:
| | | | | December 31, |
| | | | | 2010 | | 2009 |
| | | | | (in millions) |
| | Liabilities for Derivative Contracts with Credit Downgrade Triggers | | $ | 20 | | $ | 10 |
| | Amount of Collateral AEP Subsidiaries Would Have Been Required to Post | | | 45 | | | 34 |
| | Amount Attributable to RTO and ISO Activities | | | 44 | | | 29 |
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 under outstanding debt 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 represents: (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 co llateral 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 December 31, 2010 and 2009:
| | December 31, | |
| | 2010 | | 2009 | |
| | (in millions) | |
| Liabilities for Contracts with Cross Default Provisions Prior to Contractual | | | | | | |
| Netting Arrangements | | $ | 401 | | | $ | 567 | |
| Amount of Cash Collateral Posted | | | 81 | | | | 15 | |
| Additional Settlement Liability if Cross Default Provision is Triggered | | | 213 | | | | 199 | |
11. FAIR VALUE MEASUREMENTS
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 December 31, 2010 and 2009 are summarized in the following table:
| | | | December 31, |
| | | | 2010 | | 2009 |
| | | | Book Value | | Fair Value | | Book Value | | Fair Value |
| | | | (in millions) |
| | Long-term Debt | | $ | 16,811 | | $ | 18,285 | | $ | 17,498 | | $ | 18,479 |
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 payment of debt. See “Other Temporary Investments” section of Note 1.
The following is a summary of Other Temporary Investments:
| | | | | | 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 | |
| | | | | | | | | | | | | | | | | |
| | | | | | 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 payment of debt. |
The following table provides the activity for our debt and equity securities within Other Temporary Investments for the years ended December 31, 2010, 2009 and 2008:
| | Years Ended December 31, | |
| | 2010 | | 2009 | | 2008 | |
| | (in millions) | |
| Proceeds From Investment Sales | | $ | 455 | | | $ | 35 | | | $ | 1,185 | |
| Purchases of Investments | | | 503 | | | | 82 | | | | 1,118 | |
| Gross Realized Gains on Investment Sales | | | 16 | | | | - | | | | - | |
| Gross Realized Losses on Investment Sales | | | - | | | | - | | | | - | |
At December 31, 2010 and 2009, we had no Other Temporary Investments with an unrealized loss position. In June 2009, we recorded $9 million ($6 million, net of tax) of other-than-temporary impairments of Other Temporary Investments for equity investments of our protected cell captive insurance company. At December 31, 2010, 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.
Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal
I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. See “Nuclear Trust Funds” section of Note 1.
The following is a summary of nuclear trust fund investments at December 31, 2010 and December 31, 2009:
| | | | | | December 31, |
| | | | | | 2010 | | 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 | | $ | 20 | | $ | - | | $ | - | | $ | 14 | | $ | - | | $ | - |
| | Fixed Income Securities: | | | | | | | | | | | | | | | | | | |
| | | United States Government | | | 461 | | | 23 | | | (1) | | | 401 | | | 13 | | | (4) |
| | | Corporate Debt | | | 59 | | | 4 | | | (2) | | | 57 | | | 5 | | | (2) |
| | | State and Local Government | | | 341 | | | (1) | | | - | | | 369 | | | 8 | | | 1 |
| | | | Subtotal Fixed Income Securities | | | 861 | | | 26 | | | (3) | | | 827 | | | 26 | | | (5) |
| | Equity Securities - Domestic | | | 634 | | | 183 | | | (123) | | | 551 | | | 234 | | | (119) |
| | Spent Nuclear Fuel and | | | | | | | | | | | | | | | | | | |
| | | Decommissioning Trusts | | $ | 1,515 | | $ | 209 | | $ | (126) | | $ | 1,392 | | $ | 260 | | $ | (124) |
The following table provides the securities activity within the decommissioning and SNF trusts for the years ended December 31, 2010, 2009 and 2008:
| | Years Ended December 31, | |
| | 2010 | | 2009 | | 2008 | |
| | (in millions) | |
| Proceeds From Investment Sales | | $ | 1,362 | | | $ | 713 | | | $ | 732 | |
| Purchases of Investments | | | 1,415 | | | | 771 | | | | 804 | |
| Gross Realized Gains on Investment Sales | | | 12 | | | | 28 | | | | 33 | |
| Gross Realized Losses on Investment Sales | | | 2 | | | | 1 | | | | 7 | |
The adjusted cost of debt securities was $835 million and $801 million as of December 31, 2010 and 2009, respectively.
The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at December 31, 2010 was as follows:
| | Fair Value | |
| | of Debt | |
| | Securities | |
| | (in millions) | |
| Within 1 year | | $ | 22 | |
| 1 year – 5 years | | | 306 | |
| 5 years – 10 years | | | 257 | |
| After 10 years | | | 276 | |
| Total | | $ | 861 | |
Fair Value Measurements of Financial Assets and Liabilities
For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1.
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 December 31, 2010 and 2009. 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 |
| | December 31, 2010 |
| | | | | | | | | | | | | |
| | | | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| | Assets: | (in millions) |
| | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (a) | $ | 170 | | $ | - | | $ | - | | $ | 124 | | $ | 294 |
| | | | | | | | | | | | | | | | | | |
| | Other Temporary Investments | | | | | | | | | | | | | | |
| | Restricted Cash (a) | | 184 | | | - | | | - | | | 41 | | | 225 |
| | Fixed Income Securities: | | | | | | | | | | | | | | |
| | | Mutual Funds | | 69 | | | - | | | - | | | - | | | 69 |
| | | Variable Rate Demand Notes | | - | | | 97 | | | - | | | - | | | 97 |
| | Equity Securities - Mutual Funds (b) | | 25 | | | - | | | - | | | - | | | 25 |
| | Total Other Temporary Investments | | 278 | | | 97 | | | - | | | 41 | | | 416 |
| | | | | | | | | | | | | | | | | | |
| | Risk Management Assets | | | | | | | | | | | | | | |
| | Risk Management Commodity Contracts (c) (f) | | 20 | | | 1,432 | | | 112 | | | (1,013) | | | 551 |
| | Cash Flow Hedges: | | | | | | | | | | | | | | |
| | | Commodity Hedges (c) | | 11 | | | 17 | | | - | | | (15) | | | 13 |
| | | Fair Value Hedges | | - | | | 7 | | | - | | | - | | | 7 |
| | | Interest Rate/Foreign Currency Hedges | | - | | | 25 | | | - | | | - | | | 25 |
| | Dedesignated Risk Management Contracts (d) | | - | | | - | | | - | | | 46 | | | 46 |
| | Total Risk Management Assets | | 31 | | | 1,481 | | | 112 | | | (982) | | | 642 |
| | | | | | | | | | | | | | | | | | |
| | Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (e) | | - | | | 8 | | | - | | | 12 | | | 20 |
| | Fixed Income Securities: | | | | | | | | | | | | | | |
| | | 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) | | 634 | | | - | | | - | | | - | | | 634 |
| | Total Spent Nuclear Fuel and Decommissioning Trusts | | 634 | | | 869 | | | - | | | 12 | | | 1,515 |
| | | | | | | | | | | | | | | | | | |
| | Total Assets | $ | 1,113 | | $ | 2,447 | | $ | 112 | | $ | (805) | | $ | 2,867 |
| | | | | | | | | | | | | | | | | | |
| | Liabilities: | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | Risk Management Liabilities | | | | | | | | | | | | | | |
| | Risk Management Commodity Contracts (c) (f) | $ | 25 | | $ | 1,325 | | $ | 27 | | $ | (1,114) | | $ | 263 |
| | Cash Flow Hedges: | | | | | | | | | | | | | | |
| | | Commodity Hedges (c) | | 4 | | | 13 | | | - | | | (15) | | | 2 |
| | | Fair Value Hedges | | - | | | 1 | | | - | | | - | | | 1 |
| | | Interest Rate/Foreign Currency Hedges | | - | | | 4 | | | - | | | - | | | 4 |
| | Total Risk Management Liabilities | $ | 29 | | $ | 1,343 | | $ | 27 | | $ | (1,129) | | $ | 270 |
| Assets and Liabilities Measured at Fair Value on a Recurring Basis |
| December 31, 2009 |
| | | | | | | | | | | | |
| | | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | (in millions) |
| | | | | | | | | | | | | | | | | |
| Cash and Cash Equivalents (a) | $ | 427 | | $ | - | | $ | - | | $ | 63 | | $ | 490 |
| | | | | | | | | | | | | | | | | |
| Other Temporary Investments | | | | | | | | | | | | | | |
| Restricted Cash (a) | | 198 | | | - | | | - | | | 25 | | | 223 |
| Fixed Income Securities: | | | | | | | | | | | | | | |
| | Mutual Funds | | 57 | | | - | | | - | | | - | | | 57 |
| | Variable Rate Demand Notes | | - | | | 45 | | | - | | | - | | | 45 |
| Equity Securities (b): | | | | | | | | | | | | | | |
| | Domestic | | 16 | | | - | | | - | | | - | | | 16 |
| | Mutual Funds | | 22 | | | - | | | - | | | - | | | 22 |
| Total Other Temporary Investments | | 293 | | | 45 | | | - | | | 25 | | | 363 |
| | | | | | | | | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | | 8 | | | 1,609 | | | 72 | | | (1,119) | | | 570 |
| Cash Flow Hedges: | | | | | | | | | | | | | | |
| | Commodity Hedges (c) | | 1 | | | 11 | | | - | | | (4) | | | 8 |
| Dedesignated Risk Management Contracts (d) | | - | | | - | | | - | | | 25 | | | 25 |
| Total Risk Management Assets | | 9 | | | 1,620 | | | 72 | | | (1,098) | | | 603 |
| | | | | | | | | | | | | | | | | |
| Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | | | | | |
| Cash and Cash Equivalents (e) | | - | | | 3 | | | - | | | 11 | | | 14 |
| Fixed Income Securities: | | | | | | | | | | | | | | |
| | United States Government | | - | | | 401 | | | - | | | - | | | 401 |
| | Corporate Debt | | - | | | 57 | | | - | | | - | | | 57 |
| | State and Local Government | | - | | | 369 | | | - | | | - | | | 369 |
| | | Subtotal Fixed Income Securities | | - | | | 827 | | | - | | | - | | | 827 |
| Equity Securities - Domestic (b) | | 551 | | | - | | | - | | | - | | | 551 |
| Total Spent Nuclear Fuel and Decommissioning Trusts | | 551 | | | 830 | | | - | | | 11 | | | 1,392 |
| | | | | | | | | | | | | | | | | |
| Total Assets | $ | 1,280 | | $ | 2,495 | | $ | 72 | | $ | (999) | | $ | 2,848 |
| | | | | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Risk Management Liabilities | | | | | | | | | | | | | | |
| Risk Management Commodity Contracts (c) (g) | $ | 11 | | $ | 1,415 | | $ | 10 | | $ | (1,205) | | $ | 231 |
| Cash Flow Hedges: | | | | | | | | | | | | | | |
| | Commodity Hedges (c) | | - | | | 16 | | | - | | | (4) | | | 12 |
| | Interest Rate/Foreign Currency Hedges | | - | | | 5 | | | - | | | - | | | 5 |
| Total Risk Management Liabilities | $ | 11 | | $ | 1,436 | | $ | 10 | | $ | (1,209) | | $ | 248 |
| | (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 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 2017-2028; Level 3 matures $18 million in 2011, $24 million in periods 2012-2014, $16 million in periods 2015-2016 and $27 million in periods 2017-2028. Risk management commodity contracts are substantially comprised of power contracts. |
| | (g) | The December 31, 2009 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) million in periods 2011-2013 and ($1) million in periods 2014-2015; Level 2 matures $65 million in 2010, $84 million in periods 2011-2013, $22 million in periods 2014-2015 and $23 million in periods 2016-2028; Level 3 matures $17 million in 2010, $16 million in periods 2011-2013, $8 million in periods 2014-2015 and $21 million in periods 2016-2028. |
There have been no transfers between Level 1 and Level 2 during the year ended December 31, 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 Management |
| Year Ended December 31, 2010 | | Assets (Liabilities) |
| | | | (in millions) |
| Balance as of December 31, 2009 | | $ | 62 |
| Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | | | 5 |
| Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) | | | |
| | Relating to Assets Still Held at the Reporting Date (a) | | | 63 |
| Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | | - |
| Purchases, Issuances and Settlements (c) | | | (25) |
| Transfers into Level 3 (d) (h) | | | 18 |
| Transfers out of Level 3 (e) (h) | | | (53) |
| Changes in Fair Value Allocated to Regulated Jurisdictions (g) | | | 15 |
| Balance as of December 31, 2010 | | $ | 85 |
| | | | Net Risk Management |
| Year Ended December 31, 2009 | | Assets (Liabilities) |
| | | | (in millions) |
| Balance as of December 31, 2008 | | $ | 49 |
| 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) | | | 44 |
| Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | | | - |
| Purchases, Issuances and Settlements (c) | | | (17) |
| Transfers in and/or out of Level 3 (f) | | | (25) |
| Changes in Fair Value Allocated to Regulated Jurisdictions (g) | | | 15 |
| Balance as of December 31, 2009 | | $ | 62 |
| | | | Net Risk | | | | | | |
| | | | Management | | Other | | Investments |
| | | | Assets | | Temporary | | in Debt |
| Year Ended December 31, 2008 | | (Liabilities) | | Investments | | Securities |
| | | | (in millions) |
| Balance as of December 31, 2007 | | $ | 49 | | $ | - | | $ | - |
| Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | - | | | - | | | - |
| Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) | | | | | | | | | |
| | Relating to Assets Still Held at the Reporting Date (a) | | | 12 | | | - | | | - |
| Realized and Unrealized Gains (Losses) Included in Other | | | | | | | | | |
| | Comprehensive Income | | | - | | | - | | | - |
| Purchases, Issuances and Settlements (c) | | | - | | | (118) | | | (17) |
| Transfers in and/or out of Level 3 (f) | | | (36) | | | 118 | | | 17 |
| Changes in Fair Value Allocated to Regulated Jurisdictions (g) | | | 24 | | | - | | | - |
| Balance as of December 31, 2008 | | $ | 49 | | $ | - | | $ | - |
| | (a) | Included in revenues on our 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 liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. |
| | (g) | Relates to the net gains (losses) of those contracts that are not reflected on our 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. |
12. INCOME TAXES
The details of our consolidated income taxes before discontinued operations and extraordinary loss as reported are as follows:
| | | Years Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (in millions) | |
| Federal: | | | | | | | | | |
| Current | | $ | (134 | ) | | $ | (575 | ) | | $ | 164 | |
| Deferred | | | 760 | | | | 1,171 | | | | 456 | |
| Total Federal | | | 626 | | | | 596 | | | | 620 | |
| | | | | | | | | | | | | |
| State and Local: | | | | | | | | | | | | |
| Current | | | (20 | ) | | | (76 | ) | | | (1 | ) |
| Deferred | | | 38 | | | | 55 | | | | 22 | |
| Total State and Local | | | 18 | | | | (21 | ) | | | 21 | |
| | | | | | | | | | | | | |
| International: | | | | | | | | | | | | |
| Current | | | (1 | ) | | | - | | | | 1 | |
| Deferred | | | - | | | | - | | | | - | |
| Total International | | | (1 | ) | | | - | | | | 1 | |
| | | | | | | | | | | | | |
| Total Income Tax Expense Before Discontinued | | | | | | | | | | | | |
| Operations and Extraordinary Loss | | $ | 643 | | | $ | 575 | | | $ | 642 | |
The following is a reconciliation of our consolidated difference between the amount of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported.
| | Years Ended December 31, |
| | 2010 | | 2009 | | 2008 |
| | (in millions) |
| Net Income | $ | 1,218 | | $ | 1,365 | | $ | 1,388 |
| Discontinued Operations, Net of Income Tax of $(10) million in 2008 | | - | | | - | | | (12) |
| Extraordinary Loss, Net of Income Tax of $3 million in 2009 | | - | | | 5 | | | - |
| Income Before Discontinued Operations and Extraordinary Loss | | 1,218 | | | 1,370 | | | 1,376 |
| Income Tax Expense Before Discontinued Operations and Extraordinary Loss | | 643 | | | 575 | | | 642 |
| Pretax Income | $ | 1,861 | | $ | 1,945 | | $ | 2,018 |
| | | | | | | | | |
| Income Taxes on Pretax Income at Statutory Rate (35%) | $ | 651 | | $ | 681 | | $ | 706 |
| Increase (Decrease) in Income Taxes resulting from the following items: | | | | | | | | |
| | | Depreciation | | 47 | | | 31 | | | 23 |
| | | Investment Tax Credits, Net | | (16) | | | (19) | | | (19) |
| | | Energy Production Credits | | (20) | | | (15) | | | (20) |
| | | State and Local Income Taxes | | 11 | | | (14) | | | 13 |
| | | Removal Costs | | (19) | | | (19) | | | (21) |
| | | AFUDC | | (33) | | | (36) | | | (24) |
| | | Medicare Subsidy | | 12 | | | (11) | | | (12) |
| | | Tax Reserve Adjustments | | (16) | | | (6) | | | 2 |
| | | Other | | 26 | | | (17) | | | (6) |
| Total Income Tax Expense Before Discontinued Operations and | �� | | | | | | | |
| | Extraordinary Loss | $ | 643 | | $ | 575 | | $ | 642 |
| | | | | | | | | |
| Effective Income Tax Rate | | 34.6 | % | | | 29.6 | % | | | 31.8 | % |
The following table shows elements of the net deferred tax liability and significant temporary differences:
| | | December 31, | |
| | | 2010 | | | 2009 | |
| | | (in millions) | |
| Deferred Tax Assets | | $ | 2,519 | | | $ | 2,493 | |
| Deferred Tax Liabilities | | | (10,009 | ) | | | (9,065 | ) |
| Net Deferred Tax Liabilities | | $ | (7,490 | ) | | $ | (6,572 | ) |
| | | | | | | | | |
| Property-Related Temporary Differences | | $ | (5,301 | ) | | $ | (4,714 | ) |
| Amounts Due from Customers for Future Federal Income Taxes | | | (250 | ) | | | (229 | ) |
| Deferred State Income Taxes | | | (622 | ) | | | (523 | ) |
| Securitized Transition Assets | | | (651 | ) | | | (712 | ) |
| Regulatory Assets | | | (867 | ) | | | (862 | ) |
| Accrued Pensions | | | 218 | | | | 335 | |
| Deferred Income Taxes on Other Comprehensive Loss | | | 207 | | | | 203 | |
| Accrued Nuclear Decommissioning | | | (395 | ) | | | (356 | ) |
| All Other, Net | | | 171 | | | | 286 | |
| Net Deferred Tax Liabilities | | $ | (7,490 | ) | | $ | (6,572 | ) |
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.
At December 31, 2010, we have federal general business credit carryforwards of $64 million. If these credits are not utilized, they will expire in the years 2028 through 2030.
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. The years 2007 and 2008 are currently under examination. 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. Management 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.
We sustained federal, state and local net income tax operating losses in 2009 driven primarily by bonus depreciation, a change in tax accounting method related to units of property and other book versus tax temporary differences. As a result, we accrued current federal, state and local income tax benefits in 2009. We realized the federal cash flow benefit in 2010 as there was sufficient capacity in prior periods to carry the net operating loss back. Most of our state and local jurisdictions do not provide for a net operating loss carry back. We anticipate future taxable income will be sufficient to realize the tax benefit. As such, we determined that a valuation allowance is unnecessary.
We recognize interest accruals related to uncertain tax positions in interest income or expense, as applicable, and penalties in Other Operation in accordance with the accounting guidance for “Income Taxes.”
The following table shows amounts reported for interest expense, interest income and reversal of prior period interest expense:
| | Years Ended December 31, | |
| | 2010 | | 2009 | | 2008 | |
| | (in millions) | |
| Interest Expense | | $ | 8 | | | $ | 1 | | | $ | 10 | |
| Interest Income | | | 11 | | | | 5 | | | | 21 | |
| Reversal of Prior Period Interest Expense | | | 5 | | | | 5 | | | | 13 | |
The following table shows balances for amounts accrued for the receipt of interest and the payment of interest and penalties:
| | December 31, | |
| | 2010 | | 2009 | |
| | (in millions) | |
| Accrual for Receipt of Interest | | $ | 42 | | | $ | 30 | |
| Accrual for Payment of Interest and Penalties | | | 21 | | | | 18 | |
The reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
| | | 2010 | | | 2009 | | | 2008 | |
| | | (in millions) | |
| Balance at January 1, | | $ | 237 | | | $ | 237 | | | $ | 222 | |
| Increase - Tax Positions Taken During a Prior Period | | | 40 | | | | 56 | | | | 41 | |
| Decrease - Tax Positions Taken During a Prior Period | | | (43 | ) | | | (65 | ) | | | (45 | ) |
| Increase - Tax Positions Taken During the Current Year | | | - | | | | 16 | | | | 27 | |
| Decrease - Tax Positions Taken During the Current Year | | | (6 | ) | | | - | | | | (5 | ) |
| Increase - Settlements with Taxing Authorities | | | - | | | | 1 | | | | 3 | |
| Decrease - Settlements with Taxing Authorities | | | (2 | ) | | | - | | | | - | |
| Decrease - Lapse of the Applicable Statute of Limitations | | | (7 | ) | | | (8 | ) | | | (6 | ) |
| Balance at December 31, | | $ | 219 | | | $ | 237 | | | $ | 237 | |
The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is $112 million, $137 million and $147 million for 2010, 2009 and 2008, respectively. We believe there will be no significant net increase or decrease in unrecognized tax benefits within 12 months of the reporting date.
Federal Tax Legislation
Under the Energy Tax Incentives Act of 2005, we filed applications with the United States Department of Energy and the IRS in 2008 for the West Virginia IGCC project and in July 2008 the IRS allocated the project $134 million in credits. In September 2008, we entered into a memorandum of understanding with the IRS concerning the requirements of claiming the credits. We had until July 2010 to meet certain minimum requirements under the agreement with the IRS or the credits would be forfeited. In July 2010, we forfeited the allocated tax credits.
The Economic Stimulus Act of 2008 provided enhanced expensing provisions for certain assets placed in service in 2008 and a 50% bonus depreciation provision similar to the one in effect in 2003 through 2004 for assets placed in service in 2008. The enacted provisions did not have a material impact on net income or financial condition, but provided a cash flow benefit of approximately $200 million in 2008.
The American Recovery and Reinvestment Tax Act of 2009 provided for several new grant programs and expanded tax credits and an extension of the 50% bonus depreciation provision enacted in the Economic Stimulus Act of 2008. The enacted provisions did not have a material impact on net income or financial condition. However, the bonus depreciation contributed to the 2009 federal net operating tax loss that resulted in a 2010 cash flow benefit of $419 million.
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 year ended December 31, 2010, deferred tax assets decreased $56 million, partially offset 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 the 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 provisions will not have a material impact on net income or financial condition but had a favorable impact on cash flows of $318 million in 2010.
State Tax Legislation
Under Ohio House Bill 66, in 2005, the Ohio companies established a regulatory liability for $57 million pending rate-making treatment in Ohio. For those companies in which state income taxes flow through for rate-making purposes, regulatory assets associated with the deferred state income tax liabilities were reduced by $22 million. In November 2006, the PUCO ordered that the $57 million be amortized to income as an offset to power supply contract losses incurred by CSPCo and OPCo for sales to Ormet. As of December 31, 2008, the $57 million regulatory liability was fully amortized.
The Ohio legislation also imposed a new commercial activity tax at a fully phased-in rate of 0.26% on all Ohio gross receipts. The tax was phased-in over a five-year period that began July 1, 2005 at 23% of the full 0.26% rate. As a result of this tax, expenses of approximately $13 million, $11 million and $9 million were recorded in 2010, 2009 and 2008, respectively, in Taxes Other Than Income Taxes.
Michigan Senate Bill 0094 (MBT Act), effective January 1, 2008, provided a comprehensive restructuring of Michigan’s principal business tax. The law replaced the Michigan Single Business Tax. The MBT Act is composed of a new tax which is calculated based upon two components: (a) a business income tax (BIT) imposed at a rate of 4.95% and (b) a modified gross receipts tax (GRT) imposed at a rate of 0.80%, which will collectively be referred to as the BIT/GRT tax calculation. The law also includes significant credits for engaging in Michigan-based activity.
In March 2008, legislation was signed providing for, among other things, a reduction in the West Virginia corporate income tax rate from 8.75% to 8.5% beginning in 2009. The corporate income tax rate could also be reduced to 7.75% in 2012 and 7% in 2013 contingent upon the state government achieving certain minimum levels of shortfall reserve funds. We have evaluated the impact of the law change and the application of the law change will not materially impact our net income, cash flows or financial condition.
13. LEASES
Leases of property, plant and equipment are for periods up to 60 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.
Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows:
| | | Years Ended December 31, | |
| Lease Rental Costs | | 2010 | | 2009 | | 2008 | |
| | | (in millions) | |
| Net Lease Expense on Operating Leases | | | $ | 343 | | | $ | 354 | | | $ | 368 | |
| Amortization of Capital Leases | | | | 97 | | | | 83 | | | | 97 | |
| Interest on Capital Leases | | | | 26 | | | | 13 | | | | 16 | |
| Total Lease Rental Costs | | | $ | 466 | | | $ | 450 | | | $ | 481 | |
The following table shows the property, plant and equipment under capital leases and related obligations recorded on our Consolidated Balance Sheets. Capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on our Consolidated Balance Sheets.
| | | December 31, | |
| Property, Plant and Equipment Under Capital Leases | | 2010 | | 2009 | |
| | | (in millions) | |
| Generation | | | $ | 97 | | | $ | 75 | |
| Distribution | | | | - | | | | - | |
| Other Property, Plant and Equipment | | | | 482 | | | | 379 | |
| Construction Work in Progress | | | | - | | | | - | |
| Total Property, Plant and Equipment Under Capital Leases | | | | 579 | | | | 454 | |
| Accumulated Amortization | | | | 108 | | | | 139 | |
| Net Property, Plant and Equipment Under Capital Leases | | | $ | 471 | | | $ | 315 | |
| Obligations Under Capital Leases | | | | | | | |
| Noncurrent Liability | | | $ | 398 | | | $ | 244 | |
| Liability Due Within One Year | | | | 76 | | | | 73 | |
| Total Obligations Under Capital Leases | | | $ | 474 | | | $ | 317 | |
Future minimum lease payments consisted of the following at December 31, 2010:
| | | | | | Noncancelable | |
| Future Minimum Lease Payments | | Capital Leases | | | Operating Leases | |
| | | (in millions) | |
| 2011 | | $ | 100 | | | $ | 306 | |
| 2012 | | | 88 | | | | 286 | |
| 2013 | | | 71 | | | | 261 | |
| 2014 | | | 59 | | | | 241 | |
| 2015 | | | 47 | | | | 226 | |
| Later Years | | | 286 | | | | 1,349 | |
| Total Future Minimum Lease Payments | | $ | 651 | | | $ | 2,669 | |
| Less Estimated Interest Element | | | 177 | | | | | |
| Estimated Present Value of Future Minimum | | | | | | | | |
| Lease Payments | | $ | 474 | | | | | |
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) for approximately $137 million to replace existing operating and capital 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 were to be terminated in 2011 since GE exercised the termination provision related to these leases in 2008. Approximately $16 million of currently leased assets were not included in the refinancing, but will be purchased or refinanced in 2011. In addition, approximately $40 million of operating leases that were previously under lease with GE are now recorded as capital leases after the refinancing. These obligations are included in the future minimum lease payments schedule earlier in this note.
For equipment under the GE master lease agreements, the lessor is guaranteed receipt of up to 84% 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 84% of the unamortized balance. For 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 between the actual fair value and the residual value guarantee. At December 31, 2010, the maximum potential loss for these lease agreements was approximately $14 million ($9 million, net of tax) 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.
Rockport Lease
AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors.
The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it equally to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. Neither AEGCo, I&M nor AEP has an ownership interest in the Owner Trustee and do not guarantee its debt. The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2010 are as follows:
| Future Minimum Lease Payments | | AEGCo | | | I&M | |
| | | (in millions) | |
| 2011 | | $ | 74 | | | $ | 74 | |
| 2012 | | | 74 | | | | 74 | |
| 2013 | | | 74 | | | | 74 | |
| 2014 | | | 74 | | | | 74 | |
| 2015 | | | 74 | | | | 74 | |
| Later Years | | | 517 | | | | 517 | |
| Total Future Minimum Lease Payments | | $ | 887 | | | $ | 887 | |
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 $17 million for I&M and $19 million for SWEPCo for the remaining railcars as of December 31, 2010. These obligations are included in the future minimum lease payments schedule earlier in this note.
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 suffi cient sales price to avoid any loss.
Sabine Dragline Lease
During 2009, Sabine, an entity consolidated in accordance with the accounting guidance for “Variable Interest Entities,” entered into capital lease arrangements with a nonaffiliated company to finance the purchase of two electric draglines to be used for Sabine’s mining operations totaling $47 million. The amounts included in the lease represented the aggregate fair value of the existing equipment and a sale and leaseback transaction for additional dragline rebuild costs required to keep the dragline operational. In addition to the 2009 transactions, Sabine has one additional $53 million dragline completed in 2008 that was financed under a capital lease. These capital lease assets are included in Other Property, Plant and Equipment on our December 31, 2010 and 2009 Consolidated Balance Sheets. The short-term and long-term capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on our December 31, 2010 and 2009 Consolidated Balance Sheets. The future payment obligations are included in our future minimum lease payments schedule earlier in this note.
I&M Nuclear Fuel Lease
In December 2007, I&M entered into a sale-and-leaseback transaction with Citicorp Leasing, Inc. (CLI), an unrelated, unconsolidated, wholly-owned subsidiary of Citibank, N.A. to lease nuclear fuel for I&M’s Cook Plant. In December 2007, I&M sold a portion of its unamortized nuclear fuel inventory to CLI at cost for $85 million. The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 60 months. The future payment obligations of $3 million are included in our future minimum lease payments schedule earlier in this note. The net capital lease asset is included in Other Property, Plant and Equipment and the short-term and long-term capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities, respectively, on our December 31, 2010 and 2009 Consolidated Balance Sheets. The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2010 are as follows, based on estimated fuel burn:
| Future Minimum Lease Payments | | Amount |
| | | (in millions) |
| 2011 | | | $ | 2 |
| 2012 | | | | 1 |
| Total Future Minimum Lease Payments | | | $ | 3 |
14. FINANCING ACTIVITIES
AEP Common Stock
In April 2009, we issued 69 million shares of common stock at $24.50 per share for net proceeds of $1.64 billion, which were primarily used to repay cash drawn under our credit facilities in the second quarter of 2009.
Set forth below is a reconciliation of common stock share activity for the years ended December 31, 2010, 2009 and 2008:
| | | | | | Held in | |
| Shares of AEP Common Stock | | Issued | | | Treasury | |
| Balance, December 31, 2007 | | | 421,926,696 | | | | 21,499,992 | |
| Issued | | | 4,394,552 | | | | - | |
| Treasury Stock Contributed to AEP Foundation | | | - | | | | (1,250,000 | ) |
| Balance, December 31, 2008 | | | 426,321,248 | | | | 20,249,992 | |
| Issued | | | 72,012,017 | | | | - | |
| Treasury Stock Acquired | | | - | | | | 28,866 | |
| Balance, December 31, 2009 | | | 498,333,265 | | | | 20,278,858 | |
| Issued | | | 2,781,616 | | | | - | |
| Treasury Stock Acquired | | | - | | | | 28,867 | |
| Balance, December 31, 2010 | | | 501,114,881 | | | | 20,307,725 | |
Preferred Stock
Information about the components of preferred stock of our subsidiaries is as follows:
| | December 31, 2010 |
| | Call Price | | Shares | | Shares | | |
| | Per Share (a) | | Authorized (b) | | Outstanding (c) | | Amount |
| Not Subject to Mandatory Redemption: | | | | | | | (in millions) |
| | 4.00% - 5.00% | $102-$110 | | 1,525,903 | | 600,641 | | $ | 60 |
| | | | | | | | |
| | December 31, 2009 |
| | Call Price | | Shares | | Shares | | |
| | Per Share (a) | | Authorized (b) | | Outstanding (c) | | Amount |
| Not Subject to Mandatory Redemption: | | | | | | | (in millions) |
| | 4.00% - 5.00% | $102-$110 | | 1,525,903 | | 606,627 | | $ | 61 |
| (a) | At the option of the subsidiary, the shares may be redeemed at the call price plus accrued dividends. The involuntary liquidation preference is $100 per share for all outstanding shares. If the subsidiary defaults on preferred stock dividend payments for a period of one year or longer, preferred stock holders are entitled, voting separately as one class, to elect the number of directors necessary to constitute a majority of the full board of directors of the subsidiary. |
| (b) | As of December 31, 2010 and 2009, our subsidiaries had 14,494,227 and 14,488,294 shares of $100 par value preferred stock, respectively, 22,200,000 shares of $25 par value preferred stock and 7,822,535 and 7,822,482 shares of no par value preferred stock, respectively, that were authorized but unissued. Total shares authorized but unissued include shares not subject to mandatory redemption described in the above table. |
| (c) | The number of preferred stock shares redeemed was 5,986 shares and 251 shares in 2010 and 2009, respectively. There were no preferred stock shares redeemed in 2008. |
| |
| | | Weighted | | | | |
| | | Average | | | | |
| | | | | | Interest | | | | | | | | | | |
| | | Rate at | | | | Outstanding at |
| | | December 31, | | Interest Rate Ranges at December 31, | | December 31, |
| Type of Debt and Maturity | | 2010 | | 2010 | | 2009 | | 2010 | | 2009 |
| | | | | | | | | (in millions) |
| Senior Unsecured Notes | | | | | | | | | | | | |
| | 2010-2015 | | 4.99% | | 0.702%-6.375% | | 0.464%-6.375% | | $ | 3,318 | | $ | 4,258 |
| | 2016-2021 | | 6.12% | | 5.00%-7.95% | | 5.00%-7.95% | | | 4,020 | | | 4,020 |
| | 2029-2040 | | 6.41% | | 5.625%-8.13% | | 5.625%-8.13% | | | 4,331 | | | 4,138 |
| | | | | | | | | | | | | | |
| Pollution Control Bonds (a) | | | | | | | | | | | | |
| | 2010-2015 (b) | | 2.95% | | 0.29%-6.25% | | 0.22%-7.125% | | | 1,300 | | | 800 |
| | 2017-2025 | | 5.12% | | 4.45%-6.05% | | 0.23%-6.05% | | | 443 | | | 595 |
| | 2026-2042 | | 5.19% | | 4.40%-6.30% | | 0.20%-6.30% | | | 520 | | | 764 |
| | | | | | | | | | | | | | |
| Notes Payable (c) | | | | | | | | | | | | |
| | 2011-2026 | | 5.44% | | 2.07%-8.03% | | 4.47%-8.03% | | | 396 | | | 326 |
| | | | | | | | | | | | | | |
| Securitization Bonds | | | | | | | | | | | | |
| | 2010-2020 | | 5.36% | | 4.98%-6.25% | | 4.98%-6.25% | | | 1,847 | | | 1,995 |
| | | | | | | | | | | | | | |
| Junior Subordinated Debentures (d) | | | | | | | | | | | | |
| | 2063 | | 8.75% | | 8.75% | | 8.75% | | | 315 | | | 315 |
| | | | | | | | | | | | | | |
| Spent Nuclear Fuel Obligation (e) | | | | | | | | | 265 | | | 265 |
| | | | | | | | | | | | | | |
| Other Long-term Debt | | | | | | | | | | | | |
| | 2011-2059 | | 1.72% | | 1.3125%-13.718% | | 1.25%-13.718% | | | 91 | | | 88 |
| | | | | | | | | | | | | | | | |
| Unamortized Discount (net) | | | | | | | | | (35) | | | (66) |
| Total Long-term Debt Outstanding | | | | | | | | | 16,811 | | | 17,498 |
| Less Portion Due Within One Year | | | | | | | | | 1,309 | | | 1,741 |
| Long-term Portion | | | | | | | | $ | 15,502 | | $ | 15,757 |
| | (a) | For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks, standby bond purchase agreements and insurance policies support certain series. |
| | (b) | Certain pollution control bonds are subject to mandatory redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity and repayment purposes based on the mandatory redemption date. |
| | (c) | Notes payable represent outstanding promissory notes issued under term loan agreements and revolving credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. |
| | (d) | Debentures will mature on March 1, 2063, subject to extensions to no later than March 1, 2068, and are callable at par any time on or after March 1, 2013. |
| | (e) | Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6). |
At December 31, 2010, $50 million of PSO’s Senior Unsecured Notes, which are due within one year, are classified as long-term debt due to our intent and ability to refinance these notes on a long-term basis. In January 2011, PSO issued $250 million of 4.4% Senior Unsecured Notes due in 2021, demonstrating the ability to refinance these obligations on a long-term basis.
At December 31, 2009, approximately $472 million of variable-rate, tax-exempt bonds were outstanding. These bonds, which are short-term obligations, were classified as long-term due to our intent and ability to refinance each obligation on a long-term basis. At December 31, 2009, our $478 million credit facility had non-cancelable terms in excess of one year, demonstrating the ability to refinance these short-term obligations on a long-term basis.
Long-term debt outstanding at December 31, 2010 is payable as follows:
| | | | | | | | | | | | After | | |
| | 2011 | | 2012 | | 2013 | | 2014 | | 2015 | | 2015 | | Total |
| | (in millions) |
| Principal Amount | $ | 1,309 | | $ | 815 | | $ | 1,344 | | $ | 941 | | $ | 1,490 | | $ | 10,947 | | $ | 16,846 |
| Unamortized Discount | | | | | | | | | | | | | | | | | | | | (35) |
| Total Long-term Debt Outstanding | | | | | | | | | | | | | | | | | | | $ | 16,811 |
In January 2011, TCC retired $92 million of its outstanding Securitization Bonds.
In February 2011, APCo issued $65 million of 2% Pollution Control Bonds due in 2041 with a 2012 mandatory put date.
As of December 31, 2010, trustees held, on our behalf, $303 million of our reacquired variable rate tax-exempt long-term debt.
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 capitalization 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, 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 December 31, 2010, 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.
Lines of Credit and Short-term Debt
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. As of December 31, 2010, we had credit facilities totaling $3 billion to support our commercial paper program (see “Credit Facilities” section below). The maximum amount of commercial paper outstanding during 2010 was $868 million and the weighted average interest rate of commercial paper outstanding during the ye ar was 0.43%. Our outstanding short-term debt was as follows:
| | | | December 31, |
| | | | 2010 | | 2009 |
| | | | Outstanding | | Interest | | Outstanding | | Interest |
| Type of Debt | Amount | Rate (a) | | Amount | Rate (a) |
| | | (in millions) | | | | | (in millions) | | | |
| Securitized Debt for Receivables (b) | | $ | 690 | | 0.31 | % | | $ | - | | - | |
| Commercial Paper | | | 650 | | 0.52 | % | | | 119 | | 0.26 | % |
| Line of Credit – Sabine Mining Company (c) | | | 6 | | 2.15 | % | | | 7 | | 2.06 | % |
| Total Short-term Debt | | $ | 1,346 | | | | | $ | 126 | | | |
| (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, of which $750 million may be issued under the credit facility that matures in April 2012 as letters of credit. In June 2010, we terminated one of the $1.5 billion facilities, which was scheduled to mature in March 2011, and replaced it with a new $1.5 billion credit facility which matures in June 2013 and allows for the issuance of up to $600 million as letters of credit. As of December 31, 2010, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $124 million.
In June 2010, we reduced a $627 million credit agreement that matures in April 2011 to $478 million. Under the facility, we may issue letters of credit. As of December 31, 2010, $477 million of letters of credit were issued by subsidiaries under this credit agreement to support variable rate Pollution Control Bonds.
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 Consolidated Balance Sheet. See “ASU 2009-16 ‘Transfers and Servicing’ ” section of Note 2 for 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 t o 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:
| | | Years Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (dollars in millions) | |
| Proceeds from Sale of Accounts Receivable | | $ | N/A | | | $ | 7,043 | | | $ | 7,717 | |
| Loss on Sale of Accounts Receivable | | | N/A | | | | 3 | | | | 20 | |
| Average Variable Discount Rate on Sale of | | | | | | | | | | | | |
| Accounts Receivable | | | N/A | | | | 0.57 | % | | | 3.19 | % |
| Effective Interest Rates on Securitization of | | | | | | | | | | | | |
| Accounts Receivable | | | 0.31 | % | | | N/A | | | | N/A | |
| Net Uncollectible Accounts Receivable Written Off | | | 22 | | | | 28 | | | | 23 | |
| | | | | | | | | | | | | |
| | | December 31, | |
| | | 2010 | | | 2009 | |
| | | (in millions) | |
| Accounts Receivable Retained Interest and Pledged as Collateral | | | | | | |
| Less Uncollectible Accounts | | $ | 923 | | | $ | 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 | | | 690 | | | | 656 | |
| Derecognized Accounts Receivable | | | N/A | | | | 631 | |
| Delinquent Securitized Accounts Receivable | | | 50 | | | | 29 | |
| Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable | | | 26 | | | | 20 | |
| Unbilled Receivables Related to Securitization/Sale of Accounts Receivable | | | 354 | | | | 376 | |
| | | | | | | | | |
| N/A Not Applicable | | | | | | | | |
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.
15. STOCK-BASED COMPENSATION
As approved by shareholder vote, the Amended and Restated American Electric Power System Long-Term Incentive Plan (LTIP) authorizes the use of 20,000,000 shares of AEP common stock for various types of stock-based compensation awards, including stock options, to employees. A maximum of 10,000,000 shares may be used under this plan for full value share awards, which includes performance units, restricted shares and restricted stock units. The AEP Board of Directors and shareholders last approved the LTIP in 2010. The following sections provide further information regarding each type of stock-based compensation award granted by the Human Resources Committee of the Board of Directors (HR Committee).
Stock Options
We did not grant stock options in 2010, 2009 or 2008 but we do have outstanding stock options from grants in earlier periods that vested or were exercised in these years. The exercise price of all outstanding stock options equaled or exceeded the market price of AEP’s common stock on the date of grant. All outstanding stock options were granted with a ten-year term and generally vested, subject to the participant’s continued employment, in approximately equal 1/3 increments on January 1st of the year following the first, second and third anniversary of the grant date. We record compensation cost for stock options over the vesting period based on the fair value on the grant date. The LTIP does not specify a maximum contractual term for stock options.
The total fair value of stock options vested and the total intrinsic value of options exercised are as follows:
| | | Years Ended December 31, | |
| Stock Options | | 2010 | | 2009 | | 2008 | |
| | | (in thousands) | |
| Fair Value of Stock Options Vested | | | $ | - | | | $ | 25 | | | $ | 25 | |
| Intrinsic Value of Options Exercised (a) | | | | 2,058 | | | | 106 | | | | 655 | |
| (a) | Intrinsic value is calculated as market price at exercise dates less the option exercise price. |
A summary of AEP stock option transactions during the years ended December 31, 2010, 2009 and 2008 is as follows:
| | | | 2010 | | 2009 | | 2008 |
| | | | | | Weighted | | | | Weighted | | | | Weighted |
| | | | | | Average | | | | Average | | | | Average |
| | | | | | Exercise | | | | Exercise | | | | Exercise |
| | | | Options | | Price | | Options | | Price | | Options | | Price |
| | | | (in thousands) | | | | | (in thousands) | | | | | (in thousands) | | | |
| Outstanding at January 1, | 1,089 | | $ | 32.78 | | 1,128 | | $ | 32.73 | | 1,196 | | $ | 32.69 |
| | | Granted | - | | | N/A | | - | | | N/A | | - | | | N/A |
| | | Exercised/Converted | (448) | | | 31.53 | | (21) | | | 27.20 | | (68) | | | 31.97 |
| | | Forfeited/Expired | (90) | | | 38.44 | | (18) | | | 36.28 | | - | | | N/A |
| Outstanding at December 31, | 551 | | | 32.88 | | 1,089 | | | 32.78 | | 1,128 | | | 32.73 |
| | | | | | | | | | | | | | | |
| Options Exercisable at December 31, | 551 | | $ | 32.88 | | 1,089 | | $ | 32.78 | | 1,125 | | $ | 32.72 |
The following table summarizes information about AEP stock options outstanding and exercisable at December 31, 2010:
| | | | Number | | Weighted | | | | |
| | | | of Options | | Average | | Weighted | | |
| 2010 Range of | | Outstanding | | Remaining | | Average | | Aggregate |
| Exercise Prices | | and Exercisable | | Life | | Exercise Price | | Intrinsic Value |
| | | (in thousands) | | (in years) | | | | | (in thousands) |
| $27.06-27.95 | | 266 | | 2.20 | | $ | 27.44 | | $ | 2,273 |
| $30.76-38.65 | | 159 | | 3.10 | | | 31.26 | | | 778 |
| $44.10-49.00 | | 126 | | 0.50 | | | 46.40 | | | - |
| Total | | 551 | | 2.08 | | | 32.88 | | | 3,051 |
We include the proceeds received from exercised stock options in common stock and paid-in capital.
Performance Units
Our performance units have a value upon vesting equal to the market value of shares of AEP common stock. The number of performance units held is multiplied by the performance score to determine the actual number of performance units realized. The performance score is determined at the end of the performance period based on performance measures, which include both performance and market conditions, established for each grant at the beginning of the performance period by the HR Committee and can range from 0% to 200%. For the three-year performance and vesting period ending in 2009 and earlier performance periods, performance units are paid in cash or stock at the employee’s election unless they are needed to satisfy a participant’s stock ownership requirement. Starting with the t hree-year performance and vesting period ending in 2010 and later, performance units are paid in cash, unless they are needed to satisfy a participant’s stock ownership requirement. In that case, the number of units needed to satisfy the participant’s largest stock ownership requirement is mandatorily deferred as AEP Career Shares until after the end of the participant’s AEP career. AEP Career Shares are a form of non-qualified deferred compensation that have a value equivalent to shares of AEP common stock and are paid in cash after the participant’s termination of employment. Amounts equivalent to cash dividends on both performance units and
AEP Career Shares accrue as additional units. We recorded compensation cost for performance units over the three-year vesting period. The liability for both the performance units and AEP Career Shares, recorded in Employee Benefits and Pension Obligations on our Consolidated Balance Sheets, is adjusted for changes in value. The fair value of performance unit awards is based on the estimated performance score and the current 20-day average closing price of AEP common stock at the date of valuation.
The HR Committee awarded performance units and reinvested dividends on outstanding performance units and AEP Career Shares for the years ended December 31, 2010, 2009 and 2008 as follows:
| | | Years Ended December 31, |
| Performance Units | | 2010 | | 2009 | | 2008 |
| Awarded Units (in thousands) | | | 736 | | | 1,179 | | | 1,384 |
| Weighted Average Unit Fair Value at Grant Date | | $ | 35.43 | | $ | 34.32 | | $ | 30.11 |
| Vesting Period (in years) | | | 3 | | | 3 | | | 3 |
| | | | | | | | | | | |
| Performance Units and AEP Career Shares | | Years Ended December 31, |
| (Reinvested Dividends Portion) | | 2010 | | 2009 | | 2008 |
| Awarded Units (in thousands) | | | 211 | | | 224 | | | 149 |
| Weighted Average Grant Date Fair Value | | $ | 34.70 | | $ | 28.82 | | $ | 37.21 |
| Vesting Period (in years) | | | (a) | | | (a) | | | (a) |
| | (a) | The vesting period for the reinvested dividends on performance units is equal to the remaining life of the related performance units. Dividends on AEP Career Shares vest immediately upon grant. |
Performance scores and final awards are determined and certified by the HR Committee in accordance with the pre-established performance measures within approximately a month after the end of the performance period. The HR Committee has discretion to reduce or eliminate the value of final awards, but may not increase them. The performance scores for all open performance periods are dependent on two equally-weighted performance measures: (a) three-year total shareholder return measured relative to the utility industry segment of the Standard and Poor’s 500 Index and (b) three-year cumulative earnings per share measured relative to an AEP Board of Directors approved target. The value of each performance unit earned equals the average closing price o f AEP common stock for the last 20 business days of the performance period.
The certified performance scores and units earned for the three-year period ended December 31, 2010, 2009 and 2008 were as follows:
| | Years Ended December 31, |
| | 2010 | | 2009 | | 2008 |
| Certified Performance Score | 55.8 | % | | 73.5 | % | | 120.3 | % |
| Performance Units Earned | 489,013 | | 593,175 | | 1,088,302 |
| Performance Units Manditorily Deferred as AEP Career Shares | 33,501 | | 26,635 | | 42,214 |
| Performance Units Voluntarily Deferred into the Incentive Compensation | | | | | |
| | Deferral Program | 6,583 | | 27,855 | | 66,415 |
| Performance Units to be Paid in Cash | 448,929 | | 538,685 | | 979,673 |
The cash payouts for the years ended December 31, 2010, 2009 and 2008 were as follows:
| | Years Ended December 31, |
| | 2010 | | 2009 | | 2008 |
| | (in thousands) |
| Cash Payouts for Performance Units | | $ | 18,683 | | | $ | 30,034 | | | $ | 52,960 |
| Cash Payouts for AEP Career Share Distributions | | | 3,594 | | | | 2,184 | | | | 1,236 |
Restricted Shares and Restricted Stock Units
The independent members of the AEP Board of Directors granted 300,000 restricted shares to the then Chairman, President and CEO on January 2, 2004 upon the commencement of his AEP employment. Of these restricted shares, 50,000 vested on January 1, 2005, 50,000 vested on January 1, 2006, 66,666 vested on November 30, 2009 and 66,667 vested on November 30, 2010. The remaining 66,667 restricted shares will vest on November 30, 2011, subject to his continued AEP employment through that date. Compensation cost for restricted shares is measured at fair value on the grant date and recorded over the vesting period. Fair value is determined by multiplying the number of shares granted by the grant date market closing price, which was $30.76. The maximum term for these restricted shar es is eight years and dividends on these restricted shares are paid in cash. AEP has not granted other restricted shares.
The HR Committee also grants restricted stock units (RSUs), which generally vest, subject to the participant’s continued employment, over at least three years in approximately equal annual increments on the anniversaries of the grant date. For awards granted prior to 2009, additional RSUs granted as dividends vest on the last vesting date associated with that RSU grant. For awards granted in 2009 and later, additional RSUs granted as dividends vest on the same date as the underlying RSUs on which the dividends were awarded. Compensation cost is measured at fair value on the grant date and recorded over the vesting period. Fair value is determined by multiplying the number of units granted by the grant date market closing price. The maximum contractual term of outstanding RS Us is five years from the grant date.
In 2010, the HR Committee granted a total of 165,520 of RSUs to four CEO succession candidates to better ensure the retention of these candidates. These grants vest, subject to the candidates’ continuous employment, in three approximately equal installments on August 3, 2013, August 3, 2014 and August 3, 2015.
The HR Committee awarded RSUs, including units awarded for dividends, for the years ended December 31, 2010, 2009 and 2008 as follows:
| | | | Years Ended December 31, |
| Restricted Stock Units | | 2010 | | 2009 | | 2008 |
| Awarded Units (in thousands) | | | 873 | | | 130 | | | 56 |
| Weighted Average Grant Date Fair Value | | $ | 35.24 | | $ | 29.29 | | $ | 41.69 |
The total fair value and total intrinsic value of restricted shares and restricted stock units vested during the years ended December 31, 2010, 2009 and 2008 were as follows:
| | | | Years Ended December 31, |
| Restricted Shares and Restricted Stock Units | | 2010 | | 2009 | | 2008 |
| | | (in thousands) |
| Fair Value of Restricted Shares and Restricted Stock Units Vested | | $ | 6,044 | | $ | 6,573 | | $ | 2,619 |
| Intrinsic Value of Restricted Shares and Restricted Stock Units Vested (a) | | | 5,993 | | | 5,445 | | | 2,534 |
| | | | | | | | | | |
| (a) | Intrinsic value is calculated as market price at exercise date. |
A summary of the status of our nonvested restricted shares and RSUs as of December 31, 2010 and changes during the year ended December 31, 2010 are as follows:
| | | | | Weighted | |
| | | | | Average | |
| Nonvested Restricted Shares and | | | | Grant Date | |
| Restricted Stock Units | | Shares/Units | | Fair Value | |
| | | (in thousands) | | | | |
| Nonvested at January 1, 2010 | | | 366 | | | $ | 34.12 | |
| Granted | | | 873 | | | | 35.24 | |
| Vested | | | (173 | ) | | | 35.00 | |
| Forfeited | | | (40 | ) | | | 35.01 | |
| Nonvested at December 31, 2010 | | | 1,026 | | | | 34.88 | |
The total aggregate intrinsic value of nonvested restricted shares and RSUs as of December 31, 2010 was $37 million and the weighted average remaining contractual life was 3.09 years.
Other Stock-Based Plans
We also have a Stock Unit Accumulation Plan for Non-employee Directors providing each non-employee director with AEP stock units as a substantial portion of their quarterly compensation for their services as a director. Amounts equivalent to cash dividends on the stock units accrue as additional AEP stock units. The non-employee directors vest immediately upon award of the stock units. Stock units are paid in cash upon termination of board service or up to 10 years later if the participant so elects. Cash payments for stock units are calculated based on the average closing price of AEP common stock for the 20 trading days immediately preceding the payment date.
We recorded the compensation cost for stock units when the units are awarded and adjusted the liability for changes in value based on the current 20-day average closing price of AEP common stock at the date of valuation.
We had no material cash payouts for stock unit distributions for the years ended December 31, 2010, 2009 and 2008.
The Board of Directors awarded stock units, including units awarded for dividends, for the years ended December 31, 2010, 2009 and 2008 as follows:
| | | | Years Ended December 31, |
| Stock Unit Accumulation Plan for Non-Employee Directors | | 2010 | | 2009 | | 2008 |
| Awarded Units (in thousands) | | | 54 | | | 56 | | | 43 |
| Weighted Average Grant Date Fair Value | | $ | 34.67 | | $ | 29.56 | | $ | 37.72 |
Share-based Compensation Plans
Compensation cost and the actual tax benefit realized for the tax deductions from compensation cost for share-based payment arrangements recognized in income and total compensation cost capitalized in relation to the cost of an asset for the years ended December 31, 2010, 2009 and 2008 were as follows:
| | | | Years Ended December 31, | |
| Share-based Compensation Plans | | 2010 | | 2009 | | 2008 | |
| | | (in thousands) | |
| Compensation Cost for Share-based Payment Arrangements (a) | | $ | 28,116 | | $ | 31,165 | | $ | (18,028) | (b) |
| Actual Tax Benefit Realized | | | 9,841 | | | 10,908 | | | (6,310) | (b) |
| Total Compensation Cost Capitalized | | | 4,689 | | | 5,956 | | | (5,026) | (b) |
| Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on our Consolidated Statements of Income. |
| (b) | In 2008, AEP’s declining total shareholder return and lower stock price significantly reduced the accruals for performance units. |
During the years ended December 31, 2010, 2009 and 2008, there were no significant modifications affecting any of our share-based payment arrangements.
As of December 31, 2010, there was $81 million of total unrecognized compensation cost related to unvested share-based compensation arrangements granted under the LTIP. Unrecognized compensation cost related to the performance units and AEP Career Shares will change as the fair value is adjusted each period and forfeitures for all award types are realized. Our unrecognized compensation cost will be recognized over a weighted-average period of 1.84 years.
Cash received from stock options exercised and actual tax benefit realized for the tax deductions from stock options exercised during the years ended December 31, 2010, 2009 and 2008 were as follows:
| | | Years Ended December 31, |
| Share-based Compensation Plans | | 2010 | | 2009 | | 2008 |
| | | (in thousands) |
| Cash Received from Stock Options Exercised | | $ | 14,134 | | $ | 567 | | $ | 2,170 |
| Actual Tax Benefit Realized for the Tax Deductions from Stock Options Exercised | | | 706 | | | 35 | | | 219 |
Our practice is to use authorized but unissued shares to fulfill share commitments for stock option exercises and RSU vesting. Although we do not currently anticipate any changes to this practice, we could use treasury shares, shares acquired in the open market specifically for distribution under the LTIP or any combination thereof for this purpose. The number of new shares issued to fulfill vesting RSUs is generally reduced to offset AEP’s tax withholding obligation.
16. PROPERTY, PLANT AND EQUIPMENT
Depreciation, Depletion and Amortization
We provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class as follows:
| 2010 | | Regulated | | Nonregulated |
| | | | | | | Annual | | | | | | | | | | Annual | | | | |
| Functional | | Property, | | | | Composite | | | | | | Property, | | | | Composite | | | | |
| Class of | | Plant and | | Accumulated | | Depreciation | | Depreciable | | Plant and | | Accumulated | | Depreciation | | Depreciable |
| Property | | Equipment | | Depreciation | | Rate Ranges | | Life Ranges | | Equipment | | Depreciation | | Rate Ranges | | Life Ranges |
| | | (in millions) | | | | | | | (in years) | | (in millions) | | | | | | | (in years) |
| Generation | | $ | 14,147 | | $ | 6,537 | | 1.6 | - | 3.8 | % | | 9 | - | 132 | | $ | 10,205 | | $ | 3,788 | | 2.2 | - | 5.1 | % | | 20 | - | 70 |
| Transmission | | | 8,576 | | | 2,481 | | 1.4 | - | 3.0 | % | | 25 | - | 87 | | | - | | | - | | - | - | - | % | | - | - | - |
| Distribution | | | 14,208 | | | 3,607 | | 2.4 | - | 3.9 | % | | 11 | - | 75 | | | - | | | - | | - | - | - | % | | - | - | - |
| CWIP | | | 2,615 | (a) | | 47 | | N.M. | | N.M. | | | 143 | | | 9 | | N.M. | | N.M. |
| Other | | | 2,685 | | | 1,268 | | 3.0 | - | 12.5 | % | | 5 | - | 55 | | | 1,161 | | | 329 | | N.M. | | N.M. |
| Total | | $ | 42,231 | | $ | 13,940 | | | | | | | | | | | $ | 11,509 | | $ | 4,126 | | | | | | | | | |
| 2009 | | Regulated | | Nonregulated |
| | | | | | | Annual | | | | | | | | | | Annual | | | | |
| Functional | | Property, | | | | Composite | | | | | | Property, | | | | Composite | | | | |
| Class of | | Plant and | | Accumulated | | Depreciation | | Depreciable | | Plant and | | Accumulated | | Depreciation | | Depreciable |
| Property | | Equipment | | Depreciation | | Rate Ranges | | Life Ranges | | Equipment | | Depreciation | | Rate Ranges | | Life Ranges |
| | | (in millions) | | | | | | | (in years) | | (in millions) | | | | | | | (in years) |
| Generation | | $ | 13,047 | | $ | 6,460 | | 1.6 | - | 3.8 | % | | 9 | - | 132 | | $ | 9,998 | | $ | 3,479 | | 1.9 | - | 3.3 | % | | 20 | - | 70 |
| Transmission | | | 8,315 | | | 2,478 | | 1.4 | - | 2.7 | % | | 25 | - | 87 | | | - | | | - | | - | - | - | % | | - | - | - |
| Distribution | | | 13,549 | | | 3,421 | | 2.4 | - | 3.9 | % | | 11 | - | 75 | | | - | | | - | | - | - | - | % | | - | - | - |
| CWIP | | | 2,866 | (a) | | (19) | | N.M. | | N.M. | | | 165 | | | 6 | | N.M. | | N.M. |
| Other | | | 2,616 | | | 1,130 | | 4.2 | - | 12.8 | % | | 5 | - | 55 | | | 1,128 | | | 385 | | N.M. | | N.M. |
| Total | | $ | 40,393 | | $ | 13,470 | | | | | | | | | | | $ | 11,291 | | $ | 3,870 | | | | | | | | | |
| 2008 | | Regulated | | Nonregulated |
| | | | Annual | | | | | | Annual | | | | |
| | | | Composite | | | | | | Composite | | | | |
| | | | Depreciation | | Depreciable | | Depreciation | | Depreciable |
| Functional Class of Property | | Rate Ranges | | Life Ranges | | Rate Ranges | | Life Ranges |
| | | | | | | | | (in years) | | | | | | | (in years) |
| Generation | | 1.6 | - | 3.5 | % | | 9 | - | 132 | | 2.6 | - | 5.1 | % | | 20 | - | 61 |
| Transmission | | 1.4 | - | 2.7 | % | | 25 | - | 87 | | - | - | - | % | | - | - | - |
| Distribution | | 2.4 | - | 3.9 | % | | 11 | - | 75 | | - | - | - | % | | - | - | - |
| CWIP | | N.M. | | N.M. | | N.M. | | N.M. |
| Other | | 4.9 | - | 11.3 | % | | 5 | - | 55 | | N.M. | | N.M. |
| | | | | | | | | | | | | | | | | | | | |
| (a) | Includes CWIP related to SWEPCo's Arkansas jurisdictional share of the Turk Plant. |
| | | | | | | | | | | | | | | | | | | | |
| N.M. Not Meaningful | | |
We provide for depreciation, depletion and amortization of coal-mining assets over each asset's estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. We use either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. We include these costs in the cost of coal charged to fuel expense.
For rate-regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred.
As of January 1, 2010, DHLC was deconsolidated and is now reported as an equity investment on our 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.
Asset Retirement Obligations (ARO)
We record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for our legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities, as well as for nuclear decommissioning of our Cook Plant. We have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which we have assets. Generally, such easements are perpetual and require only the retirement and removal of our assets upon the cessation of the property’s use. We do not estimate the retirement for such easements because we plan to use our facilities indefinitely. The retirement obligation would only be recognized if and when we abandon or cease the use of specific easements, which is not expected.
The following is a reconciliation of the 2010 and 2009 aggregate carrying amounts of ARO:
| | | Carrying | |
| | | Amount | |
| | | of ARO | |
| | | (in millions) | |
| ARO at December 31, 2008 | | $ | 1,158 | |
| Accretion Expense | | | 73 | |
| Liabilities Incurred | | | 47 | |
| Liabilities Settled | | | (24) | |
| Revisions in Cash Flow Estimates | | | 5 | |
| ARO at December 31, 2009 (a) | | | 1,259 | |
| DHLC Deconsolidation (c) | | | (12) | |
| Accretion Expense | | | 75 | |
| Liabilities Incurred | | | 32 | |
| Liabilities Settled | | | (20) | |
| Revisions in Cash Flow Estimates | | | 64 | |
| ARO at December 31, 2010 (b) | | $ | 1,398 | |
| | | | | | |
| (a) | The current portion of our ARO, totaling $5 million, is included in Other Current Liabilities on our 2009 Consolidated Balance Sheet. | |
| (b) | The current portion of our ARO, totaling $4 million, is included in Other Current Liabilities on our 2010 Consolidated Balance Sheet. | |
| (c) | We adopted ASU 2009-17 effective January 1, 2010 and deconsolidated DHLC. As a result, we record only 50% of the final reclamation based on our share of the obligation instead of the previous 100%. | |
As of December 31, 2010 and 2009, our ARO liability was $1.4 billion and $1.3 billion, respectively, and included $930 million and $878 million, respectively, for nuclear decommissioning of the Cook Plant. As of December 31, 2010 and 2009, the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $1.2 billion and $1.1 billion, respectively, and are recorded in Spent Nuclear Fuel and Decommissioning Trusts on our Consolidated Balance Sheets.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Our amounts of allowance for borrowed, including interest capitalized, and equity funds used during construction is summarized in the following table:
| | Years Ended December 31, | |
| | 2010 | | 2009 | | 2008 | |
| | (in millions) | |
| Allowance for Equity Funds Used During Construction | | $ | 77 | | | $ | 82 | | | $ | 45 | |
| Allowance for Borrowed Funds Used During Construction | | | 53 | | | | 67 | | | | 75 | |
Jointly-owned Electric Facilities
We have electric facilities that are jointly-owned with nonaffiliated companies. Using our own financing, we are obligated to pay a share of the costs of these jointly-owned facilities in the same proportion as our ownership interest. Our proportionate share of the operating costs associated with such facilities is included in our Consolidated Statements of Income and the investments and accumulated depreciation are reflected in our Consolidated Balance Sheets under Property, Plant and Equipment as follows:
| | | | | | | Company’s Share at December 31, 2010 |
| | | | | | | | | Construction | | |
| | Fuel | Percent of | Utility Plant | Work in | Accumulated |
| | Type | Ownership | in Service | Progress | Depreciation |
| | | | | | | (in millions) |
| W.C. Beckjord Generating Station (Unit No. 6) (a) | Coal | | 12.5 | % | | $ | 19 | | $ | - | | $ | 8 |
| Conesville Generating Station (Unit No. 4) (b) | Coal | | 43.5 | % | | | 301 | | | 8 | | | 49 |
| J.M. Stuart Generating Station (c) | Coal | | 26.0 | % | | | 507 | | | 23 | | | 163 |
| Wm. H. Zimmer Generating Station (a) | Coal | | 25.4 | % | | | 771 | | | 10 | | | 366 |
| Dolet Hills Generating Station (Unit No. 1) (f) | Lignite | | 40.2 | % | | | 258 | | | 5 | | | 192 |
| Flint Creek Generating Station (Unit No. 1) (g) | Coal | | 50.0 | % | | | 116 | | | 7 | | | 62 |
| Pirkey Generating Station (Unit No. 1) (g) | Lignite | | 85.9 | % | | | 503 | | | 10 | | | 358 |
| Oklaunion Generating Station (Unit No. 1) (e) | Coal | | 70.3 | % | | | 395 | | | 4 | | | 201 |
| Turk Generating Plant (h) | Coal | | 73.33 | % | | | - | | | 971 | | | - |
| Transmission | N/A | | (d) | | | | 63 | | | 3 | | | 48 |
| | | | | | | Company’s Share at December 31, 2009 |
| | | | | | | | | Construction | | |
| | Fuel | Percent of | Utility Plant | Work in | Accumulated |
| | Type | Ownership | in Service | Progress | Depreciation |
| | | | | | | (in millions) |
| W.C. Beckjord Generating Station (Unit No. 6) (a) | Coal | | 12.5 | % | | $ | 19 | | $ | - | | $ | 8 |
| Conesville Generating Station (Unit No. 4) (b) | Coal | | 43.5 | % | | | 301 | | | 4 | | | 45 |
| J.M. Stuart Generating Station (c) | Coal | | 26.0 | % | | | 499 | | | 15 | | | 153 |
| Wm. H. Zimmer Generating Station (a) | Coal | | 25.4 | % | | | 767 | | | 4 | | | 355 |
| Dolet Hills Generating Station (Unit No. 1) (f) | Lignite | | 40.2 | % | | | 255 | | | 4 | | | 188 |
| Flint Creek Generating Station (Unit No. 1) (g) | Coal | | 50.0 | % | | | 116 | | | 5 | | | 61 |
| Pirkey Generating Station (Unit No. 1) (g) | Lignite | | 85.9 | % | | | 497 | | | 8 | | | 350 |
| Oklaunion Generating Station (Unit No. 1) (e) | Coal | | 70.3 | % | | | 390 | | | 6 | | | 195 |
| Turk Generating Plant (h) | Coal | | 73.33 | % | | | - | | | 688 | | | - |
| Transmission | N/A | | (d) | | | | 70 | | | 1 | | | 47 |
(a) Operated by Duke Energy Corporation, a nonaffiliated company. (c) Operated by The Dayton Power & Light Company, a nonaffiliated company. (d) Varying percentages of ownership. (e) Operated by PSO and also jointly-owned (54.7%) by TNC. (f) Operated by CLECO, a nonaffiliated company.
| (h) | Turk Generating Plant is currently under construction with a projected commercial operation date of 2012. SWEPCo jointly owns the plant with Arkansas Electric Cooperative Corporation (11.67%), East Texas Electric Cooperative (8.33%) and Oklahoma Municipal Power Authority (6.67%). Through December 2010, construction costs totaling $279 million have been billed to the other owners. |
N/A Not Applicable
17. 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 provides two weeks of base pay for every year of service along with other severance benefits.
We recorded a charge to expense in 2010 primarily related to the headcount reduction initiatives. We do not expect additional costs to be incurred related to this initiative.
| | | Total | |
| | | (in millions) | |
| Incurred | | $ | 293 | |
| Settled | | | 283 | |
| Adjustments | | | 7 | |
| Remaining Balance at December 31, 2010 | | $ | 17 | |
These costs relate primarily to severance benefits. They are included primarily in Other Operation on the Consolidated Statements of Income and Other Current Liabilities on the Consolidated Balance Sheets. Approximately 99% of the expense was within the Utility Operations segment.
18. UNAUDITED QUARTERLY FINANCIAL INFORMATION
In our opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of our net income for interim periods. Quarterly results are not necessarily indicative of a full year’s operations because of various factors. Our unaudited quarterly financial information is as follows:
| | | | | 2010 Quarterly Periods Ended | |
| | | | | March 31 | | June 30 | | September 30 | | December 31 | |
| | | | | (in millions - except per share amounts) | |
| Total Revenues | $ | 3,569 | | $ | 3,360 | | $ | 4,064 | | $ | 3,434 | |
| Operating Income | | 758 | | | 394 | (a) | | 1,025 | | | 486 | (b) |
| Net Income | | 346 | | | 137 | (a) | | 557 | | | 178 | (b) |
| | | | | | | | | | | | | |
| Amounts Attributable to AEP Common Shareholders: | | | | | | | | | | | | |
| | | Net Income | | 344 | | | 136 | (a) | | 555 | | | 176 | (b) |
| | | | | | | | | | | | | |
| Basic Earnings per Share Attributable to AEP | | | | | | | | | | | | |
| | Common Shareholders: | | | | | | | | | | | | |
| | | Earnings per Share (c) | | 0.72 | | | 0.28 | | | 1.16 | | | 0.37 | |
| | | | | | | | | | | | | |
| Diluted Earnings per Share Attributable to AEP | | | | | | | | | | | | |
| | Common Shareholders: | | | | | | | | | | | | |
| | | Earnings per Share (c) | | 0.72 | | | 0.28 | | | 1.16 | | | 0.37 | |
| | | | | 2009 Quarterly Periods Ended | |
| | | | | March 31 | | June 30 | | September 30 | | December 31 | |
| | | | | (in millions - except per share amounts) | |
| Total Revenues | $ | 3,458 | | $ | 3,202 | | $ | 3,547 | | $ | 3,282 | |
| Operating Income | | 750 | | | 682 | | | 858 | | | 481 | |
| Income Before Extraordinary Loss | | 363 | | | 322 | | | 446 | | | 239 | |
| Extraordinary Loss, Net of Tax | | - | | | (5) | (d) | | - | | | - | |
| Net Income | | 363 | | | 317 | | | 446 | | | 239 | |
| | | | | | | | | | | | | |
| Amounts Attributable to AEP Common Shareholders: | | | | | | | | | | | | |
| | | Income Before Extraordinary Loss | | 360 | | | 321 | | | 443 | | | 238 | |
| | | Extraordinary Loss, Net of Tax | | - | | | (5) | (d) | | - | | | - | |
| | | Net Income | | 360 | | | 316 | | | 443 | | | 238 | |
| | | | | | | | | | | | | |
| Basic Earnings (Loss) per Share Attributable to AEP | | | | | | | | | | | | |
| | Common Shareholders: | | | | | | | | | | | | |
| | | Earnings per Share Before Extraordinary Loss (c) | | 0.89 | | | 0.68 | | | 0.93 | | | 0.49 | |
| | | Extraordinary Loss per Share | | - | | | (0.01) | | | - | | | - | |
| | | Earnings per Share (c) | | 0.89 | | | 0.67 | | | 0.93 | | | 0.49 | |
| | | | | | | | | | | | | |
| Diluted Earnings (Loss) per Share Attributable to AEP | | | | | | | | | | | | |
| | Common Shareholders: | | | | | | | | | | | | |
| | | Earnings per Share Before Extraordinary Loss (c) | | 0.89 | | | 0.68 | | | 0.93 | | | 0.49 | |
| | | Extraordinary Loss per Share | | - | | | (0.01) | | | - | | | - | |
| | | Earnings per Share (c) | | 0.89 | | | 0.67 | | | 0.93 | | | 0.49 | |
| | (a) | See Note 17 for discussion of expenses related to cost reduction initiatives recorded in the second quarter of 2010. |
| | (b) | Includes a $43 million refund provision for the 2009 Significantly Excessive Earnings Test in addition to various other provisions for certain regulatory and legal matters. |
| | (c) | Quarterly Earnings Per Share amounts are meant to be stand-alone calculations and are not always additive to full-year amount due to rounding. |
| | (d) | See “SWEPCo Texas Restructuring” in “Extraordinary Item” section of Note 2 for discussion of the extraordinary loss recorded in the second quarter of 2009. |
APPALACHIAN POWER COMPANY
AND SUBSIDIARIES
| APPALACHIAN POWER COMPANY AND SUBSIDIARIES |
| SELECTED CONSOLIDATED FINANCIAL DATA |
| (in thousands) |
| |
| | | | | 2010 | | 2009 | | 2008 | | 2007 | | 2006 |
| STATEMENTS OF INCOME DATA | | | | | | | | | | | | | | | |
| Total Revenues | | $ | 3,275,103 | | $ | 2,876,655 | | $ | 2,889,156 | | $ | 2,607,269 | | $ | 2,394,028 |
| | | | | | | | | | | | | | | | | | |
| Operating Income | | $ | 381,023 | | $ | 372,525 | | $ | 312,976 | | $ | 320,826 | | $ | 365,643 |
| | | | | | | | | | | | | | | | | | |
| Income Before Extraordinary Loss | | $ | 136,668 | | $ | 155,814 | | $ | 122,863 | | $ | 133,499 | | $ | 181,449 |
| Extraordinary Loss, Net of Tax | | | - | | | - | | | - | | | (78,763) | (a) | | - |
| Net Income | | $ | 136,668 | | $ | 155,814 | | $ | 122,863 | | $ | 54,736 | | $ | 181,449 |
| | | | | | | | | | | | | | | | | | |
| BALANCE SHEETS DATA | | | | | | | | | | | | | | | |
| Total Property, Plant and Equipment | | $ | 10,239,610 | | $ | 9,800,213 | | $ | 9,427,921 | | $ | 8,738,446 | | $ | 8,000,278 |
| Accumulated Depreciation and Amortization | | | 2,843,087 | | | 2,751,443 | | | 2,675,784 | | | 2,591,833 | | | 2,476,290 |
| Total Property, Plant and Equipment – | | | | | | | | | | | | | | | |
| | Net | | $ | 7,396,523 | | $ | 7,048,770 | | $ | 6,752,137 | | $ | 6,146,613 | | $ | 5,523,988 |
| | | | | | | | | | | | | | | | | | |
| Total Assets | | $ | 9,997,153 | | $ | 9,796,413 | | $ | 8,762,664 | | $ | 7,621,684 | | $ | 7,001,798 |
| | | | | | | | | | | | | | | | | | |
| Total Common Shareholder's Equity | | $ | 2,821,679 | | $ | 2,771,577 | | $ | 2,376,591 | | $ | 2,082,032 | | $ | 2,036,174 |
| | | | | | | | | | | | | | | | | | |
| Cumulative Preferred Stock Not Subject to | | | | | | | | | | | | | | | |
| | Mandatory Redemption | | $ | 17,747 | | $ | 17,752 | | $ | 17,752 | | $ | 17,752 | | $ | 17,763 |
| | | | | | | | | | | | | | | | | | |
| Long-term Debt (b) | | $ | 3,561,141 | | $ | 3,477,306 | | $ | 3,174,512 | | $ | 2,847,299 | | $ | 2,598,664 |
| | | | | | | | | | | | | | | | | | |
| Obligations Under Capital Leases (b) | | $ | 32,731 | (c) | $ | 7,484 | | $ | 9,313 | | $ | 11,101 | | $ | 11,859 |
| (a) | Reflects a change in Virginia law for the reestablishment of regulatory assets and liabilities related to generation and supply operations in accordance with the accounting guidance for “Regulated Operations.” |
| (b) | Includes portion due within one year. |
| (c) | Obligations Under Capital Leases increased primarily due to capital leases under new master lease agreements for property that was previously leased under operating leases. |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
EXECUTIVE OVERVIEW
Company Overview
As a public utility, APCo engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 957,000 retail customers in its service territory in southwestern Virginia and southern West Virginia. APCo consolidates Cedar Coal Company, Central Appalachian Coal Company and Southern Appalachian Coal Company, its wholly-owned subsidiaries. APCo sells power at wholesale to municipalities.
Originally approved by the FERC in 1951 and subsequently amended in 1951, 1962, 1975, 1979 (twice) and 1980, the Interconnection Agreement establishes the AEP Power Pool which permits the AEP East companies to pool their generation assets on a cost basis. It establishes an allocation method for generating capacity among its members based on relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity revenues. AEP Power Pool members are compensated for their costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The capacity reserve relationship of the AEP Power Pool members changes as generating assets are added, retired or sold and relative peak demand changes. The AEP Power Pool calcula tes each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the MLR, which determines each member’s percentage share of revenues and costs.
In December 2010, each member gave notice to AEPSC and the other AEP Power Pool members of its decision to terminate the Interconnection Agreement effective January 1, 2014 or such other date approved by the FERC, subject to state regulatory input. It is unknown at this time whether the AEP 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 evalution. The AEP Power Pool members may revoke their notices of termination. If APCo experiences decreases in revenues or increases in costs as a result of the termination of the AEP Power Pool and is unable to recover the change in revenues and costs through rates, prices or additional sales, it could have an adverse impact on future net income and cash flows.
The AEP East companies are parties to a Transmission Agreement defining how they share the costs associated with their relative ownership of transmission assets. This sharing was based upon each company’s MLR until the FERC approved a new Transmission Agreement effective November 1, 2010. The impacts of the new Transmission Agreement will be phased-in for retail rates, adds KGPCo and WPCo as parties to the agreement and changes the allocation method.
Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and gas risk management activities based upon the location of such activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP generally accruing to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among the AEP East companies, PSO and SWEPCo in proportion to the marketing realization directly assigned to each zone for the current month plus the preceding eleven months.
AEPSC conducts power, gas, coal and emission allowance risk management activities on APCo’s behalf. APCo shares in the revenues and expenses associated with these risk management activities, as described in the preceding paragraph, with the other AEP East companies, PSO and SWEPCo. Power and gas risk management activities are allocated based on the existing power pool agreement and the SIA. APCo shares in coal and emission allowance risk management activities based on its proportion of fossil fuels burned by the AEP System. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas, coal and emission allowances. The electricity, gas, coal and emission allowance co ntracts include physical transactions, OTC options and financially-settled swaps and exchange-traded futures and options. AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts.
To minimize the credit requirements and operating constraints when operating within PJM, the AEP East companies as well as KGPCo and WPCo, agreed to a netting of all payment obligations incurred by any of the AEP East companies against all balances due to the AEP East companies, and to hold PJM harmless from actions that any one or more AEP East companies may take with respect to PJM.
APCo is jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to purchase power and sale activity pursuant to the SIA.
Regulatory Activity
Virginia Regulatory Activity
In July 2010, the Virginia SCC issued an order approving a $62 million annual increase based on a 10.53% return on common equity. The order denied recovery of the Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility, 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. As a result, APCo recorded a pretax loss of $29 million in the second quarter of 2010. See “2009 Virginia Base Rate Case” section of Note 4.
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. APCo’s future net income and cash flows will be reduced by the unrecoverable Virginia portion of the Beech Ridge and Grand Ridge costs until such time as the contracts are reassigned, renegotiated or terminated.
West Virginia Regulatory Activity
In December 2010, a settlement agreement was filed with the WVPSC to increase annual base rates by $54 million, effective March 2011. The settlement agreement allows APCo to defer and amortize up to $18 million of previously expensed 2009 incremental storm expenses over a period of eight years. A decision from the WVPSC is expected in March 2011. See “2010 West Virginia Base Rate Case” section of Note 4.
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 4.
Mountaineer Carbon Capture and Storage 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 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 PVF costs, which resulted in a pretax write-off of approximately $54 million in the second quarter of 2010. In December 2010, a settlement agreement was filed with the WVPSC to increase annual base rates by $60 million, effective March 2011. A decision from the WVPSC is expected in March 2011. As of December 31, 2010, APCo has recorded a noncurrent regulatory asset of $60 million related to the PVF. If APCo cannot recover its remaining investments in and expenses related to the PVF, it would reduce future net income and cash flows and impact financial condition. See “Mountaineer Carbon Capture and Storage Project” section of Note 4.
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 carbon capture and sequestration (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 December 31, 2010, APCo has incurred $14 million in total costs and has received $5 million of DOE funding resulting in a net $9 million balance included in Construction Work In Progress on the Consolidated Balance Sheets. 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 4.
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. 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 405 for additional discussion of relevant factors.
RESULTS OF OPERATIONS
KWH Sales/Degree Days
| Summary of KWH Energy Sales |
| | | | | | | | | | |
| | | Years Ended December 31, |
| | 2010 | | 2009 | | 2008 |
| | | (in millions of KWH) |
| Retail: | | | | | | | | |
| | Residential | | 13,127 | | | 12,218 | | | 12,523 |
| | Commercial | | 7,208 | | | 6,974 | | | 7,057 |
| | Industrial | | 10,774 | | | 10,388 | | | 13,794 |
| | Miscellaneous | | 869 | | | 835 | | | 835 |
| Total Retail | | 31,978 | | | 30,415 | | | 34,209 |
| | | | | | | | | |
| Wholesale | | 6,578 | | | 5,648 | | | 9,611 |
| | | | | | | | | |
| Total KWHs | | 38,556 | | | 36,063 | | | 43,820 |
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 |
| | | | | | | | | | | |
| | | | Years Ended December 31, |
| | | | 2010 | | 2009 | | 2008 |
| | | | (in degree days) |
| | | | | | | | | | | |
| | Actual - Heating (a) | | 2,636 | | | 2,214 | | | 2,236 |
| | Normal - Heating (b) | | 2,272 | | | 2,288 | | | 2,288 |
| | | | | | | | | | | |
| | Actual - Cooling (c) | | 1,530 | | | 1,053 | | | 1,116 |
| | Normal - Cooling (b) | | 1,170 | | | 1,176 | | | 1,175 |
| | | | | | | | | | | |
| | (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. |
| 2010 Compared to 2009 | |
| | | | |
| Reconciliation of Year Ended December 31, 2009 to Year Ended December 31, 2010 | |
| Net Income | |
| (in millions) | |
| | | | |
| Year Ended December 31, 2009 | | $ | 156 | |
| | | | | |
| Changes in Gross Margin: | | | | |
| Retail Margins | | | 137 | |
| Off-system Sales | | | 5 | |
| Other Revenues | | | 15 | |
| Total Change in Gross Margin | | | 157 | |
| | | | | |
| Total Expenses and Other: | | | | |
| Other Operation and Maintenance | | | (99 | ) |
| Depreciation and Amortization | | | (30 | ) |
| Taxes Other Than Income Taxes | | | (19 | ) |
| Carrying Costs Income | | | 10 | |
| Other Income | | | (4 | ) |
| Interest Expense | | | (5 | ) |
| Total Expenses and Other | | | (147 | ) |
| | | | | |
| Income Tax Expense | | | (29 | ) |
| | | | | |
| Year Ended December 31, 2010 | | $ | 137 | |
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 $137 million primarily due to the following: |
| | · | A $138 million increase in rate relief primarily due to an increase in the recovery 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 $62 million related to riders/trackers recognized in other expense items. |
| | · | A $49 million increase in residential usage primarily due to a 46% increase in cooling degree days. |
| | These increases were partially offset by: |
| | · | An $18 million decrease in industrial sales primarily due to the decreased load for APCo’s largest customer, Century Aluminum. |
| | · | An $11 million decrease due to higher capacity settlement expenses under the Interconnection Agreement net of recovery in West Virginia and environmental deferrals in Virginia. |
| | · | A $9 million decrease related to increased consumable and allowance expenses. |
| · | 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. |
| · | Other Revenues increased $15 million primarily due to increased gains on the sale of SO2 allowances as a result of favorable market prices. |
Total Expenses and Other and Income Tax Expense changed between years as follows:
| · | Other Operation and Maintenance expenses increased $99 million primarily due to the following: |
| | · | A $54 million increase due to expenses related to cost reduction initiatives. In 2010, management conducted cost reduction initiatives to reduce both labor and non-labor expenses. | |
| | · | A $54 million increase due to the write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility as denied for recovery by the Virginia SCC. | |
| | · | A $33 million increase 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. | |
| | · | A $7 million increase due to expenses related to the Mountaineer Carbon Capture and Storage Product Validation Facility. | |
| | · | A $7 million increase in steam maintenance expenses primarily due to a planned outage at the Amos Plant. | |
| | These increases were partially offset by: | |
| | · | A $49 million decrease in distribution expenses resulting from storm damage repairs in 2009. | |
| | · | A $25 million decrease due to the deferral of 2009 storm costs as allowed by the Virginia SCC in 2010. | |
| · | Depreciation and Amortization expenses increased $30 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. |
| · | Taxes Other Than Income Taxes increased $19 million primarily due to recording a West Virginia franchise tax audit settlement, a favorable franchise tax return adjustment recorded in 2009 and additional employer payroll taxes incurred related to cost reduction initiatives. |
| · | Carrying Costs Income increased $10 million primarily due to environmental construction in Virginia. |
| · | Other Income decreased $4 million primarily due to a decrease in the equity component of AFUDC as a result of the completion of environmental projects. |
| · | Interest Expense increased $5 million primarily due to a decrease in the debt component of AFUDC as a result of the completion of environmental projects. |
| · | Income Tax Expense increased $29 million primarily due to the regulatory accounting treatment of state income taxes and other book/tax differences which are accounted for on a flow-through basis and an increase in pretax book income. |
2009 Compared to 2008 | |
| | | | |
| Reconciliation of Year Ended December 31, 2008 to Year Ended December 31, 2009 | |
| Net Income | |
| (in millions) | |
| | | | |
| Year Ended December 31, 2008 | | $ | 123 | |
| | | | | |
| Changes in Gross Margin: | | | | |
| Retail Margins | | | 128 | |
| Off-system Sales | | | (27 | ) |
| Transmission Revenues | | | 2 | |
| Other Revenues | | | (2 | ) |
| Total Change in Gross Margin | | | 101 | |
| | | | | |
| Total Expenses and Other: | | | | |
| Other Operation and Maintenance | | | (33 | ) |
| Depreciation and Amortization | | | (17 | ) |
| Taxes Other Than Income Taxes | | | 9 | |
| Carrying Costs Income | | | (25 | ) |
| Other Income | | | (7 | ) |
| Interest Expense | | | 7 | |
| Total Expenses and Other | | | (66 | ) |
| | | | | |
| Income Tax Expense | | | (2 | ) |
| | | | | |
| Year Ended December 31, 2009 | | $ | 156 | |
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 $128 million primarily due to the following: |
| | · | A $144 million increase in rate relief primarily due to the impact of the Virginia base rate orders issued in October 2008 and December 2009 and increases in the recovery of construction financing costs in West Virginia. |
| | · | A $53 million increase due to the December 2008 provision for refund of off-system sales margins as ordered by the FERC related to the SIA. |
| | · | A $24 million increase due to new rates effective January 2009 for a power supply contract with KGPCo. |
| | These increases were partially offset by: |
| | · | A $62 million decrease due to higher capacity settlement expenses under the Interconnection Agreement net of recovery in West Virginia and environmental deferrals in Virginia. |
| | · | A $25 million decrease in industrial sales primarily due to suspended operations by APCo’s largest customer, Century Aluminum. |
| · | Margins from Off-system Sales decreased $27 million primarily due to lower physical sales volumes and lower margins as a result of lower market prices, partially offset by higher trading and marketing margins. |
Total Expenses and Other and Income Tax Expense changed between years as follows:
| · | Other Operation and Maintenance expenses increased $33 million primarily due to the following: |
| | · | A $49 million increase in distribution expenses resulting from storm damage repairs in 2009 and an increase in reliability spending. |
| | · | A $15 million increase in steam maintenance expenses primarily due to a planned outage at the Amos Plant. |
| | These increases were partially offset by: | |
| | · | A $26 million decrease related to the establishment of a regulatory asset in 2009 for the deferral of transmission costs. |
| | · | A $7 million decrease in employee benefit expenses. |
| · | Depreciation and Amortization expenses increased $17 million primarily due to the following: |
| | · | A $15 million increase in depreciation expense due to a greater depreciation base resulting from environmental upgrades at the Amos, Clinch River and Mountaineer Plants. |
| | · | A $2 million increase in amortization of carrying charges and depreciation expense that are being collected through the Virginia E&R surcharges. |
| · | Taxes Other Than Income Taxes decreased $9 million primarily due to a favorable franchise tax return adjustment recorded in 2009. |
| · | Carrying Costs Income decreased $25 million due to completion of reliability deferrals in Virginia in December 2008 and a decrease of environmental construction deferrals in Virginia in 2009. |
| · | Other Income decreased $7 million primarily due to higher interest income related to a tax refund in 2008 and other tax adjustments. |
| · | Interest Expense decreased $7 million primarily due to a $24 million decrease in interest expense related to a refund on off-system sales margins in accordance with the FERC’s order related to the SIA in 2008. This decrease was partially offset by a $20 million increase in interest expense due to increased long-term debt outstanding. |
| · | Income Tax Expense increased $2 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. |
FINANCIAL CONDITION
LIQUIDITY
APCo participates in the Utility Money Pool, which provides access to AEP’s liquidity. APCo 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 405 for additional discussion of liquidity.
Credit Ratings
APCo’s ultimate access to capital markets may depend on its credit ratings. 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 2010, 2009 and 2008 were as follows:
| | | Years Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (in thousands) | |
| Cash and Cash Equivalents at Beginning of Period | | $ | 2,006 | | | $ | 1,996 | | | $ | 2,195 | |
| Cash Flows from (Used for): | | | | | | | | | | | | |
| Operating Activities | | | 655,564 | | | | (29,267 | ) | | | 242,703 | |
| Investing Activities | | | (523,948 | ) | | | (529,958 | ) | | | (682,085 | ) |
| Financing Activities | | | (132,671 | ) | | | 559,235 | | | | 439,183 | |
| Net Increase (Decrease) in Cash and Cash Equivalents | | | (1,055 | ) | | | 10 | | | | (199 | ) |
| Cash and Cash Equivalents at End of Period | | $ | 951 | | | $ | 2,006 | | | $ | 1,996 | |
Operating Activities
Net Cash Flows from Operating Activities were $656 million in 2010. APCo produced Net Income of $137 million during the period and had noncash expense items of $304 million for Depreciation and Amortization and $144 million for Deferred Income Taxes, partially offset by $33 million in Carrying Costs Income. APCo contributed $37 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 $117 million inflow from Fuel, Materials and Supplies was primarily due to a reductio n in fuel inventory and a decrease in the average cost of coal per ton. The $77 million inflow from Accrued Taxes, Net was primarily due to the receipt of a 2010 income tax refund of $170 million related to 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 included bonus depreciation and the favorable impact of a change in tax accounting method related to units of property. The $63 million outflow from Accounts Receivable, Net was primarily due to an increase in accrued unbilled revenues due to usual seasonal fluctuations and timing of settlements of receivables from affiliated companies.
Net Cash Flows Used for Operating Activities were $29 million in 2009. APCo produced Net Income of $156 million during the period and had noncash expense items of $323 million for Deferred Income Taxes and $274 million for Depreciation and Amortization, partially offset by $23 million in Carrying Costs Income. The $323 million inflow for Deferred Income Taxes was 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. 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, suc h as regulatory assets and liabilities. The activity in working capital relates to a number of items. The $221 million outflow from Fuel, Materials and Supplies was primarily due to an increase in coal inventory. The $172 million outflow from Accrued Taxes, Net was primarily due to an increase in accrued tax benefits resulting from a net income tax operating loss in 2009. The $41 million outflow from Accounts Payable was primarily due to APCo’s provision for revenue refund which was paid to the AEP West companies as part of a FERC order on the SIA. The $194 million outflow from Fuel Over/Under-Recovery, Net was primarily due to a net under-recovery of fuel costs in both Virginia and West Virginia.
Net Cash Flows from Operating Activities were $243 million in 2008. APCo produced Net Income of $123 million during the period and noncash expense items of $257 million for Depreciation and Amortization and $146 million for Deferred Income Taxes, partially offset by $48 million in Carrying Costs Income. 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 $138 million inflow from Accounts Payable included APCo’s provision for revenue refund of $77 million to be paid to the AEP West companies as part of the FERC’s recent order on the SIA. The $190 million outflow in Fuel Over/Under-Recovery, Net resulted from a net under recovery of fuel cost in both Virginia and West Virginia.
Investing Activities
Net Cash Flows Used for Investing Activities in 2010, 2009 and 2008 primarily reflect construction expenditures of $534 million, $544 million and $697 million, respectively. Construction expenditures 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.
Financing Activities
Net Cash Flows Used for Financing Activities were $133 million in 2010. APCo issued $300 million of Senior Unsecured Notes and $68 million of Pollution Control Bonds. APCo retired $150 million of Senior Unsecured Notes, $100 million of Notes Payable – Affiliated and $50 million of Pollution Control Bonds. APCo reduced short-term borrowings from the Utility Money Pool by $101 million and paid $88 million in dividends on common stock.
Net Cash Flows from Financing Activities were $559 million in 2009. APCo issued $350 million of Senior Unsecured Notes and $104 million of Pollution Control Bonds. APCo also received capital contributions from the Parent of $250 million. These increases were partially offset by the retirement of $150 million of Senior Unsecured Notes. In addition, APCo increased short-term borrowings from the Utility Money Pool by $35 million.
Net Cash Flows from Financing Activities were $439 million in 2008. APCo issued $500 million of Senior Unsecured Notes and $245 million of Pollution Control Bonds. APCo also received capital contributions from the Parent of $200 million. These increases were partially offset by the retirement of $213 million of Pollution Control Bonds and $200 million of Senior Unsecured Notes. In addition, APCo reduced short-term borrowings from the Utility Money Pool by $80 million.
In February 2011, APCo issued $65 million of 2% Pollution Control Bonds due in 2041 with a 2012 mandatory put date.
CONTRACTUAL OBLIGATION INFORMATION
APCo’s contractual cash obligations include amounts reported on APCo’s Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes APCo’s contractual cash obligations at December 31, 2010:
| | Payments Due by Period |
| | |
| | | | | Less Than | | | | | | After | | |
| | Contractual Cash Obligations | | 1 year | | 2-3 years | | 4-5 years | | 5 years | | Total |
| | | | (in millions) |
| | Advances from Affiliates (a) | | $ | 128.3 | | $ | - | | $ | - | | $ | - | | $ | 128.3 |
| | Interest on Fixed Rate Portion of Long-term Debt (b) | | | 191.1 | | | 354.2 | | | 323.2 | | | 2,255.0 | | | 3,123.5 |
| | Fixed Rate Portion of Long-term Debt (c) | | | 250.0 | | | 320.0 | | | 500.1 | | | 2,269.3 | | | 3,339.4 |
| | Variable Rate Portion of Long-term Debt (d) | | | 229.7 | | | - | | | - | | | - | | | 229.7 |
| | Capital Lease Obligations (e) | | | 9.5 | | | 14.5 | | | 6.5 | | | 6.9 | | | 37.4 |
| | Noncancelable Operating Leases (e) | | | 14.3 | | | 21.5 | | | 17.6 | | | 58.0 | | | 111.4 |
| | Fuel Purchase Contracts (f) | | | 541.7 | | | 790.8 | | | 487.5 | | | 419.7 | | | 2,239.7 |
| | Energy and Capacity Purchase Contracts (g) | | | 16.4 | | | 27.3 | | | 27.0 | | | 186.4 | | | 257.1 |
| | Construction Contracts for Capital Assets (h) | | | 94.7 | | | 197.2 | | | 221.0 | | | 289.1 | | | 802.0 |
| | Total | | $ | 1,475.7 | | $ | 1,725.5 | | $ | 1,582.9 | | $ | 5,484.4 | | $ | 10,268.5 |
| (a) | Represents short-term borrowings from the Utility Money Pool. |
| (b) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2010 and do not reflect anticipated future refinancings, early redemptions or debt issuances. |
| (c) | See “Long-term Debt” section of Note 14. Represents principal only excluding interest. |
| (d) | See “Long-term Debt” section of Note 14. Represents principal only excluding interest. Variable rate debt had interest rates that ranged between 0.29% and 0.37% at December 31, 2010. |
| (e) | See Note 13. |
| (f) | Represents contractual obligations to purchase coal and other consumables as fuel for electric generation along with related transportation of the fuel. |
| (g) | Represents contractual obligations for energy and capacity purchase contracts. |
| (h) | Represents only capital assets for which APCo has signed contracts. Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs. |
APCo’s $14 million liability related to uncertainty in Income Taxes is not included above because management cannot reasonably estimate the cash flows by period.
APCo’s pension funding requirements are not included in the above table. As of December 31, 2010, management expects to make contributions to the pension plans totaling $14.7 million in 2011. Estimated contributions of $24.1 million in 2012 and $21.3 million in 2013 may vary significantly based on market returns, changes in actuarial assumptions and other factors. Based upon the benefit obligation and fair value of assets available to pay pension benefits, APCo’s pension plan obligation was 78.6% funded as of December 31, 2010.
In addition to the amounts disclosed in the contractual cash obligations table above, APCo makes additional commitments in the normal course of business. APCo’s commitments outstanding at December 31, 2010 under these agreements are summarized in the table below:
| | Amount of Commitment Expiration Per Period |
| | |
| | | | Less Than | | | | | | After | | |
| | Other Commercial Commitments | | 1 year | | 2-3 years | | 4-5 years | | 5 years | | Total |
| | | | |
| | Standby Letters of Credit (a) | | $ | 232.3 | | $ | - | | $ | - | | $ | - | | $ | 232.3 |
| (a) | APCo enters into standby letters of credit (LOCs) with third parties. These LOCs cover items such as insurance programs, security deposits, debt service reserves and variable rate Pollution Control Bonds. All of these LOCs were issued in APCo’s ordinary course of business. There is no collateral held in relation to any guarantees in excess of APCo's ownership percentages. In the event any LOC is drawn, there is no recourse to third parties. The maximum future payments of these LOCs are $232.3 million with maturities ranging from March 2011 to April 2011. See “Letters of Credit” section of Note 6. |
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” beginning on page 405 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 Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 for a discussion of the adoption and impact of new accounting pronouncements.
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 405 for a discussion of risk management activities.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Appalachian Power Company:
We have audited the accompanying consolidated balance sheets of Appalachian Power Company and subsidiaries (the "Company") as of December 31, 2010 and 2009, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Appalachian Power Company and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Columbus, Ohio
February 25, 2011
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Appalachian Power Company and subsidiaries (APCo) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. APCo’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of APCo’s internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on management’s assessment, APCo’s internal control over financial reporting was effective as of December 31, 2010.
This annual report does not include an attestation report of APCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit APCo to provide only management’s report in this annual report.
| APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
| CONSOLIDATED STATEMENTS OF INCOME | |
| For the Years Ended December 31, 2010, 2009 and 2008 | |
| (in thousands) | |
| | |
| | | 2010 | | | 2009 | | | 2008 | |
| REVENUES | | | | | | | | | |
| Electric Generation, Transmission and Distribution | | $ | 2,950,183 | | | $ | 2,604,494 | | | $ | 2,542,222 | |
| Sales to AEP Affiliates | | | 316,207 | | | | 263,389 | | | | 328,735 | |
| Other Revenues | | | 8,713 | | | | 8,772 | | | | 18,199 | |
| TOTAL REVENUES | | | 3,275,103 | | | | 2,876,655 | | | | 2,889,156 | |
| | | | | | | | | | | | | |
| EXPENSES | | | | | | | | | | | | |
| Fuel and Other Consumables Used for Electric Generation | | | 663,422 | | | | 547,266 | | | | 710,115 | |
| Purchased Electricity for Resale | | | 257,349 | | | | 246,742 | | | | 215,413 | |
| Purchased Electricity from AEP Affiliates | | | 917,616 | | | | 803,116 | | | | 785,191 | |
| Other Operation | | | 429,107 | | | | 266,763 | | | | 297,818 | |
| Maintenance | | | 211,486 | | | | 274,543 | | | | 209,766 | |
| Depreciation and Amortization | | | 304,192 | | | | 273,506 | | | | 256,626 | |
| Taxes Other Than Income Taxes | | | 110,908 | | | | 92,194 | | | | 101,251 | |
| TOTAL EXPENSES | | | 2,894,080 | | | | 2,504,130 | | | | 2,576,180 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 381,023 | | | | 372,525 | | | | 312,976 | |
| | | | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | | | |
| Interest Income | | | 1,477 | | | | 1,403 | | | | 6,371 | |
| Carrying Costs Income | | | 33,080 | | | | 22,761 | | | | 48,249 | |
| Allowance for Equity Funds Used During Construction | | | 2,967 | | | | 7,000 | | | | 8,938 | |
| Interest Expense | | | (207,649 | ) | | | (202,426 | ) | | | (209,733 | ) |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAX EXPENSE | | | 210,898 | | | | 201,263 | | | | 166,801 | |
| | | | | | | | | | | | | |
| Income Tax Expense | | | 74,230 | | | | 45,449 | | | | 43,938 | |
| | | | | | | | | | | | | |
| NET INCOME | | | 136,668 | | | | 155,814 | | | | 122,863 | |
| | | | | | | | | | | | | |
Preferred Stock Dividend Requirements Including Capital Stock Expense | | | 900 | | | | 900 | | | | 942 | |
| | | | | | | | | | | | | |
| EARNINGS ATTRIBUTABLE TO COMMON STOCK | | $ | 135,768 | | | $ | 154,914 | | | $ | 121,921 | |
| | |
| The common stock of APCo is wholly-owned by AEP. | |
| | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
| APPALACHIAN POWER COMPANY AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S |
| EQUITY AND COMPREHENSIVE INCOME (LOSS) |
| For the Years Ended December 31, 2010, 2009 and 2008 |
| (in thousands) |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | Accumulated | | |
| | | | | | | | | | | | Other | | |
| | | Common | | Paid-in | | Retained | | Comprehensive | | |
| | | Stock | | Capital | | Earnings | | Income (Loss) | | Total |
| TOTAL COMMON SHAREHOLDER'S EQUITY – | | | | | | | | | | | | | | | |
| | DECEMBER 31, 2007 | | $ | 260,458 | | $ | 1,025,149 | | $ | 831,612 | | $ | (35,187) | | $ | 2,082,032 |
| | | | | | | | | | | | | | | | |
| Adoption of Guidance for Split-Dollar Life Insurance | | | | | | | | | | | | | | | |
| | Accounting, Net of Tax of $1,175 | | | | | | | | | (2,181) | | | | | | (2,181) |
| Adoption of Guidance for Fair Value Accounting, | | | | | | | | | | | | | | | |
| | Net of Tax of $154 | | | | | | | | | (286) | | | | | | (286) |
| Capital Contribution from Parent | | | | | | 200,000 | | | | | | | | | 200,000 |
| Preferred Stock Dividends | | | | | | | | | (799) | | | | | | (799) |
| Capital Stock Expense | | | | | | 143 | | | (143) | | | | | | - |
| SUBTOTAL – COMMON SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | 2,278,766 |
| | | | | | | | | | | | | | | | | |
| COMPREHENSIVE INCOME | | | | | | | | | | | | | | | |
| Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | |
| | | Cash Flow Hedges, Net of Tax of $297 | | | | | | | | | | | | 552 | | | 552 |
| | | Amortization of Pension and OPEB Deferred Costs, | | | | | | | | | | | | | | | |
| | | | Net of Tax of $1,794 | | | | | | | | | | | | 3,333 | | | 3,333 |
| | | Pension and OPEB Funded Status, Net of Tax of $15,574 | | | | | | | | | | | | (28,923) | | | (28,923) |
| NET INCOME | | | | | | | | | 122,863 | | | | | | 122,863 |
| TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 97,825 |
| | | | | | | | | | | | | | | | | | | |
| 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 | | | | | | | | | (799) | | | | | | (799) |
| Capital Stock Expense | | | | | | 101 | | | (101) | | | | | | - |
| SUBTOTAL – COMMON SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | 2,605,792 |
| | | | | | | | | | | | | | | | |
| COMPREHENSIVE INCOME | | | | | | | | | | | | | | | |
| Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | |
| | | Cash Flow Hedges, Net of Tax of $970 | | | | | | | | | | | | (1,801) | | | (1,801) |
| | | Amortization of Pension and OPEB Deferred Costs, | | | | | | | | | | | | | | | |
| | | | Net of Tax of $2,642 | | | | | | | | | | | | 4,907 | | | 4,907 |
| | | Pension and OPEB Funded Status, Net of Tax of $3,697 | | | | | | | | | | | | 6,865 | | | 6,865 |
| NET INCOME | | | | | | | | | 155,814 | | | | | | 155,814 |
| TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 165,785 |
| | | | | | | | | | | | | | | | |
| TOTAL COMMON SHAREHOLDER'S EQUITY – | | | | | | | | | | | | | | | |
| | DECEMBER 31, 2009 | | | 260,458 | | | 1,475,393 | | | 1,085,980 | | | (50,254) | | | 2,771,577 |
| | | | | | | | | | | | | | | | |
| Common Stock Dividends | | | | | | | | | (88,000) | | | | | | (88,000) |
| Preferred Stock Dividends | | | | | | | | | (799) | | | | | | (799) |
| Capital Stock Expense | | | | | | 103 | | | (101) | | | | | | 2 |
| SUBTOTAL – COMMON SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | 2,682,780 |
| | | | | | | | | | | | | | | | |
| COMPREHENSIVE INCOME | | | | | | | | | | | | | | | |
| Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | |
| | | Cash Flow Hedges, Net of Tax of $3,843 | | | | | | | | | | | | 7,137 | | | 7,137 |
| | | Amortization of Pension and OPEB Deferred Costs, | | | | | | | | | | | | | | | |
| | | | Net of Tax of $2,247 | | | | | | | | | | | | 4,172 | | | 4,172 |
| | | Pension and OPEB Funded Status, Net of Tax of $4,888 | | | | | | | | | | | | (9,078) | | | (9,078) |
| NET INCOME | | | | | | | | | 136,668 | | | | | | 136,668 |
| TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 138,899 |
| | | | | | | | | | | | | | | | |
| TOTAL COMMON SHAREHOLDER'S EQUITY – | | | | | | | | | | | | | | | |
| | DECEMBER 31, 2010 | | $ | 260,458 | | $ | 1,475,496 | | $ | 1,133,748 | | $ | (48,023) | | $ | 2,821,679 |
| |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. |
| APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
| CONSOLIDATED BALANCE SHEETS | |
| ASSETS | |
| December 31, 2010 and 2009 | |
| (in thousands) | |
| | |
| | | 2010 | | | 2009 | |
| CURRENT ASSETS | | | | | | |
| Cash and Cash Equivalents | | $ | 951 | | | $ | 2,006 | |
| Accounts Receivable: | | | | | | | | |
| Customers | | | 166,878 | | | | 150,285 | |
| Affiliated Companies | | | 145,972 | | | | 135,686 | |
| Accrued Unbilled Revenues | | | 108,210 | | | | 68,971 | |
| Miscellaneous | | | 3,090 | | | | 6,690 | |
| Allowance for Uncollectible Accounts | | | (6,667 | ) | | | (5,408 | ) |
| Total Accounts Receivable | | | 417,483 | | | | 356,224 | |
| Fuel | | | 230,697 | | | | 343,261 | |
| Materials and Supplies | | | 89,370 | | | | 88,575 | |
| Risk Management Assets | | | 53,242 | | | | 67,956 | |
| Accrued Tax Benefits | | | 104,435 | | | | 180,708 | |
| Regulatory Asset for Under-Recovered Fuel Costs | | | 18,300 | | | | 78,685 | |
| Prepayments and Other Current Assets | | | 35,811 | | | | 36,293 | |
| TOTAL CURRENT ASSETS | | | 950,289 | | | | 1,153,708 | |
| | | | | | | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
| Electric: | | | | | | | | |
| Generation | | | 4,736,150 | | | | 4,284,361 | |
| Transmission | | | 1,852,415 | | | | 1,813,777 | |
| Distribution | | | 2,740,752 | | | | 2,642,479 | |
| Other Property, Plant and Equipment | | | 348,013 | | | | 329,497 | |
| Construction Work in Progress | | | 562,280 | | | | 730,099 | |
| Total Property, Plant and Equipment | | | 10,239,610 | | | | 9,800,213 | |
| Accumulated Depreciation and Amortization | | | 2,843,087 | | | | 2,751,443 | |
| TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 7,396,523 | | | | 7,048,770 | |
| | | | | | | | | |
| OTHER NONCURRENT ASSETS | | | | | | | | |
| Regulatory Assets | | | 1,486,625 | | | | 1,433,791 | |
| Long-term Risk Management Assets | | | 38,420 | | | | 47,141 | |
| Deferred Charges and Other Noncurrent Assets | | | 125,296 | | | | 113,003 | |
| TOTAL OTHER NONCURRENT ASSETS | | | 1,650,341 | | | | 1,593,935 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 9,997,153 | | | $ | 9,796,413 | |
| | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
| APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
| CONSOLIDATED BALANCE SHEETS | |
| LIABILITIES AND SHAREHOLDERS' EQUITY | |
| December 31, 2010 and 2009 | |
| | |
| | | 2010 | | | 2009 | |
| | | (in thousands) | |
| CURRENT LIABILITIES | | | | | | |
| Advances from Affiliates | | $ | 128,331 | | | $ | 229,546 | |
| Accounts Payable: | | | | | | | | |
| General | | | 223,144 | | | | 291,240 | |
| Affiliated Companies | | | 166,884 | | | | 157,640 | |
| Long-term Debt Due Within One Year – Nonaffiliated | | | 479,672 | | | | 200,019 | |
| Long-term Debt Due Within One Year – Affiliated | | | - | | | | 100,000 | |
| Risk Management Liabilities | | | 27,993 | | | | 25,792 | |
| Customer Deposits | | | 58,451 | | | | 57,578 | |
| Deferred Income Taxes | | | 44,180 | | | | 68,706 | |
| Accrued Taxes | | | 75,619 | | | | 65,241 | |
| Accrued Interest | | | 57,871 | | | | 58,962 | |
| Other Current Liabilities | | | 93,286 | | | | 95,292 | |
| TOTAL CURRENT LIABILITIES | | | 1,355,431 | | | | 1,350,016 | |
| | | | | | | | | |
| NONCURRENT LIABILITIES | | | | | | | | |
| Long-term Debt – Nonaffiliated | | | 3,081,469 | | | | 3,177,287 | |
| Long-term Risk Management Liabilities | | | 10,873 | | | | 20,364 | |
| Deferred Income Taxes | | | 1,642,072 | | | | 1,439,884 | |
| Regulatory Liabilities and Deferred Investment Tax Credits | | | 562,381 | | | | 526,546 | |
| Employee Benefits and Pension Obligations | | | 306,460 | | | | 312,873 | |
| Deferred Credits and Other Noncurrent Liabilities | | | 199,041 | | | | 180,114 | |
| TOTAL NONCURRENT LIABILITIES | | | 5,802,296 | | | | 5,657,068 | |
| | | | | | | | | |
| TOTAL LIABILITIES | | | 7,157,727 | | | | 7,007,084 | |
| | | | | | | | | |
| Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 17,747 | | | | 17,752 | |
| | | | | | | | | |
| Rate Matters (Note 4) | | | | | | | | |
| Commitments and Contingencies (Note 6) | | | | | | | | |
| | | | | | | | | |
| 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 | | | 1,475,496 | | | | 1,475,393 | |
| Retained Earnings | | | 1,133,748 | | | | 1,085,980 | |
| Accumulated Other Comprehensive Income (Loss) | | | (48,023 | ) | | | (50,254 | ) |
| TOTAL COMMON SHAREHOLDER’S EQUITY | | | 2,821,679 | | | | 2,771,577 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 9,997,153 | | | $ | 9,796,413 | |
| | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
| APPALACHIAN POWER COMPANY AND SUBSIDIARIES | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| For the Years Ended December 31, 2010, 2009 and 2008 | |
| (in thousands) | |
| | |
| | | 2010 | | | 2009 | | | 2008 | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net Income | | $ | 136,668 | | | $ | 155,814 | | | $ | 122,863 | |
| Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) | | | | | | | | | | | | |
| Operating Activities: | | | | | | | | | | | | |
| Depreciation and Amortization | | | 304,192 | | | | 273,506 | | | | 256,626 | |
| Deferred Income Taxes | | | 144,413 | | | | 322,626 | | | | 145,594 | |
| Carrying Costs Income | | | (33,080 | ) | | | (22,761 | ) | | | (48,249 | ) |
| Allowance for Equity Funds Used During Construction | | | (2,967 | ) | | | (7,000 | ) | | | (8,938 | ) |
| Mark-to-Market of Risk Management Contracts | | | 29,182 | | | | (15,346 | ) | | | (20,555 | ) |
| Pension Contributions to Qualified Plan Trust | | | (36,784 | ) | | | - | | | | - | |
| Fuel Over/Under-Recovery, Net | | | (13,356 | ) | | | (194,436 | ) | | | (189,543 | ) |
| Change in Regulatory Assets | | | 38,475 | | | | (84,159 | ) | | | (73,602 | ) |
| Change in Other Noncurrent Assets | | | (15,668 | ) | | | (2,926 | ) | | | (12,020 | ) |
| Change in Other Noncurrent Liabilities | | | 1,757 | | | | 3,895 | | | | (7,335 | ) |
| Changes in Certain Components of Working Capital: | | | | | | | | | | | | |
| Accounts Receivable, Net | | | (63,426 | ) | | | (14,489 | ) | | | (19,058 | ) |
| Fuel, Materials and Supplies | | | 116,530 | | | | (221,280 | ) | | | (43,748 | ) |
| Accounts Payable | | | (16,823 | ) | | | (41,370 | ) | | | 137,704 | |
| Accrued Taxes, Net | | | 76,881 | | | | (172,126 | ) | | | (5,496 | ) |
| Other Current Assets | | | 1,287 | | | | (3,608 | ) | | | (18,984 | ) |
| Other Current Liabilities | | | (11,717 | ) | | | (5,607 | ) | | | 27,444 | |
| Net Cash Flows from (Used for) Operating Activities | | | 655,564 | | | | (29,267 | ) | | | 242,703 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction Expenditures | | | (534,334 | ) | | | (543,587 | ) | | | (696,767 | ) |
| Change in Other Cash Deposits | | | 1,964 | | | | 235 | | | | (674 | ) |
| Acquisitions of Assets | | | (2,485 | ) | | | (1,116 | ) | | | (1,685 | ) |
| Proceeds from Sales of Assets | | | 4,738 | | | | 14,510 | | | | 17,041 | |
| Other Investing Activities | | | 6,169 | | | | - | | | | - | |
| Net Cash Flows Used for Investing Activities | | | (523,948 | ) | | | (529,958 | ) | | | (682,085 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Capital Contribution from Parent | | | - | | | | 250,000 | | | | 200,000 | |
| Issuance of Long-term Debt – Nonaffiliated | | | 363,726 | | | | 447,883 | | | | 735,799 | |
| Change in Advances from Affiliates, Net | | | (101,215 | ) | | | 34,658 | | | | (80,369 | ) |
| Retirement of Long-term Debt – Nonaffiliated | | | (200,019 | ) | | | (150,017 | ) | | | (412,789 | ) |
| Retirement of Long-term Debt – Affiliated | | | (100,000 | ) | | | - | | | | - | |
| Retirement of Cumulative Preferred Stock | | | (4 | ) | | | - | | | | - | |
| Principal Payments for Capital Lease Obligations | | | (7,001 | ) | | | (3,479 | ) | | | (3,922 | ) |
| Dividends Paid on Common Stock | | | (88,000 | ) | | | (20,000 | ) | | | - | |
| Dividends Paid on Cumulative Preferred Stock | | | (799 | ) | | | (799 | ) | | | (799 | ) |
| Other Financing Activities | | | 641 | | | | 989 | | | | 1,263 | |
| Net Cash Flows from (Used for) Financing Activities | | | (132,671 | ) | | | 559,235 | | | | 439,183 | |
| | | | | | | | | | | | | |
| Net Increase (Decrease) in Cash and Cash Equivalents | | | (1,055 | ) | | | 10 | | | | (199 | ) |
| Cash and Cash Equivalents at Beginning of Period | | | 2,006 | | | | 1,996 | | | | 2,195 | |
| Cash and Cash Equivalents at End of Period | | $ | 951 | | | $ | 2,006 | | | $ | 1,996 | |
| | | | | | | | | | | | | |
| SUPPLEMENTARY INFORMATION | | | | | | | | | | | | |
| Cash Paid for Interest, Net of Capitalized Amounts | | $ | 202,884 | | | $ | 209,806 | | | $ | 177,531 | |
| Net Cash Paid (Received) for Income Taxes | | | (153,205 | ) | | | (81,508 | ) | | | (72,973 | ) |
| Noncash Acquisitions Under Capital Leases | | | 22,772 | | | | 2,572 | | | | 3,242 | |
| Government Grants Included in Accounts Receivable at December 31, | | | 1,049 | | | | - | | | | - | |
| Construction Expenditures Included in Accounts Payable at December 31, | | | 66,048 | | | | 108,077 | | | | 185,469 | |
| SIA Refund Included in Accounts Payable at December 31, | | | - | | | | - | | | | 77,139 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | | | | | |
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The notes to APCo’s consolidated financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to APCo. The footnotes begin on page 246.
| | Footnote Reference |
| | |
| Organization and Summary of Significant Accounting Policies | Note 1 |
| New Accounting Pronouncements and Extraordinary Item | Note 2 |
| Rate Matters | Note 4 |
| Effects of Regulation | Note 5 |
| Commitments, Guarantees and Contingencies | Note 6 |
| Benefit Plans | Note 8 |
| Business Segments | Note 9 |
| Derivatives and Hedging | Note 10 |
| Fair Value Measurements | Note 11 |
| Income Taxes | Note 12 |
| Leases | Note 13 |
| Financing Activities | Note 14 |
| Related Party Transactions | Note 15 |
| Property, Plant and Equipment | Note 16 |
| Cost Reduction Initiatives | Note 17 |
| Unaudited Quarterly Financial Information | Note 18 |
COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
EXECUTIVE OVERVIEW
Company Overview
As a public utility, CSPCo engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 749,000 retail customers in central and southern Ohio. CSPCo consolidates Conesville Coal Preparation Company, its wholly-owned subsidiary. Effective May 2009, Colomet, Inc. merged into CSPCo. Effective September 2008, Simco, Inc. merged into Conesville Coal Preparation Company.
In October 2010, CSPCo and OPCo filed with the PUCO to merge CSPCo into OPCo. Approval of the merger will not affect CSPCo's and OPCo's rates until the PUCO approves new rates, terms and conditions for the merged company. In January 2011, CSPCo and OPCo filed with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo effective October 2011.
Originally approved by the FERC in 1951 and subsequently amended in 1951, 1962, 1975, 1979 (twice) and 1980, the Interconnection Agreement establishes the AEP Power Pool which permits the AEP East companies to pool their generation assets on a cost basis. It establishes an allocation method for generating capacity among its members based on relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity revenues. AEP Power Pool members are compensated for their costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The capacity reserve relationship of the AEP Power Pool members changes as generating assets are added, retired or sold and relative peak demand changes. The AEP Power Pool calcula tes each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the MLR, which determines each member’s percentage share of revenues and costs.
In December 2010, each member gave notice to AEPSC and the other AEP Power Pool members of its decision to terminate the Interconnection Agreement effective January 1, 2014 or such other date approved by the FERC, subject to state regulatory input. It is unknown at this time whether the AEP 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 CSPCo experiences decreases in revenues or increases in costs as a result o f the termination of the AEP Power Pool and is unable to recover the change in revenues and costs through rates, prices or additional sales, it could have an adverse impact on future net income and cash flows.
The AEP East companies are parties to a Transmission Agreement defining how they share the costs associated with their relative ownership of transmission assets. This sharing was based upon each company’s MLR until the FERC approved a new Transmission Agreement effective November 1, 2010. The impacts of the new Transmission Agreement will be phased-in for retail rates, adds KGPCo and WPCo as parties to the agreement and changes the allocation method.
In March 2007, CSPCo and AEGCo entered into a 10-year unit power agreement for the entire output from the Lawrenceburg Plant with an option for an additional 2-year period. CSPCo pays AEGCo for the capacity, depreciation, fuel, operation and maintenance and tax expenses. These payments are due regardless of whether the plant operates.
Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and gas risk management activities based upon the location of such activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP generally accruing to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among the AEP East companies, PSO and SWEPCo in proportion to the marketing realization directly assigned to each zone for the current month plus the preceding eleven months.
AEPSC conducts power, gas, coal and emission allowance risk management activities on CSPCo’s behalf. CSPCo shares in the revenues and expenses associated with these risk management activities, as described in the preceding paragraph, with the other AEP East companies, PSO and SWEPCo. Power and gas risk management activities are allocated based on the existing power pool agreement and the SIA. CSPCo shares in coal and emission allowance risk management activities based on its proportion of fossil fuels burned by the AEP System. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas, coal and emission allowances. The electricity, gas, coal and emission allowance contracts include physical transactions, OTC options and financially-settled swaps and exchange-traded futures and options. AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts.
To minimize the credit requirements and operating constraints when operating within PJM, the AEP East companies as well as KGPCo and WPCo, agreed to a netting of all payment obligations incurred by any of the AEP East companies against all balances due to the AEP East companies, and to hold PJM harmless from actions that any one or more AEP East companies may take with respect to PJM.
CSPCo is jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to purchase power and sale activity pursuant to the SIA.
Ohio Customer Choice
In CSPCo’s service territory, various competitive retail electric service (CRES) providers are targeting retail customers by offering alternative generation service. As of December 31, 2010, approximately 5,000 CSPCo retail customers have switched from CSPCo to alternative CRES providers. As a result, in comparison to 2009, CSPCo lost approximately $16 million of generation related gross margin in 2010. Management currently forecasts incremental lost margins of approximately $53 million for 2011. Management anticipates recovery of a portion of this lost margin through off-system sales.
Regulatory Activity
2009 – 2011 ESP
During 2009, the PUCO issued an order that modified and approved CSPCo’s ESP which established rates through 2011. The order also limited annual rate increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011. The order provided 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. In January 2011, the PUCO issued an order that determined that relevant CSPCo 2009 earnings were significantly excessive. As a result, the PUCO ordered CSPCo to refund $43 million of its earnings to customers, which was recorded as a revenue provision on CSPCo’s December 2010 books. See “Ohio Electric Security Plan Filings” sect ion of Note 4.
Proposed 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 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 individually vary, but on average, customers will experience net base generation increases of 1.4% in 2012 and 2.7% for the period January 2013 through May 2014. See “Ohio Electric Security Plan Filings” section of Note 4.
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. 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 405 for additional discussion of relevant factors.
RESULTS OF OPERATIONS
KWH Sales/Degree Days
| Summary of KWH Energy Sales |
| | | | | | | | | | |
| | | Years Ended December 31, |
| | 2010 | | 2009 | | 2008 |
| | | (in millions of KWH) |
| Retail: | | | | | | | | |
| | Residential | | 7,804 | | | 7,303 | | | 7,551 |
| | Commercial | | 8,709 | | | 8,532 | | | 8,772 |
| | Industrial | | 4,666 | | | 4,784 | | | 5,828 |
| | Miscellaneous | | 56 | | | 54 | | | 55 |
| Total Retail | | 21,235 | | | 20,673 | | | 22,206 |
| | | | | | | | | |
| Wholesale | | 2,950 | | | 2,822 | | | 5,463 |
| | | | | | | | | |
| Total KWHs | | 24,185 | | | 23,495 | | | 27,669 |
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 |
| | | | | | | | | | | |
| | | | Years Ended December 31, |
| | | | 2010 | | 2009 | | 2008 |
| | | | (in degree days) |
| | | | | | | | | | | |
| | Actual - Heating (a) | | 3,295 | | | 3,040 | | | 3,157 |
| | Normal - Heating (b) | | 3,036 | | | 3,054 | | | 3,187 |
| | | | | | | | | | | |
| | Actual - Cooling (c) | | 1,317 | | | 854 | | | 1,056 |
| | Normal - Cooling (b) | | 1,029 | | | 1,037 | | | 999 |
| | | | | | | | | | | |
| | (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. |
| 2010 Compared to 2009 | |
| | | | |
| Reconciliation of Year Ended December 31, 2010 to Year Ended December 31, 2009 | |
| Net Income | |
| (in millions) | |
| | | | |
| Year Ended December 31, 2009 | | $ | 272 | |
| | | | | |
| Changes in Gross Margin: | | | | |
| Retail Margins | | | (20 | ) |
| Off-system Sales | | | 22 | |
| Other Revenues | | | 4 | |
| Total Change in Gross Margin | | | 6 | |
| | | | | |
| Total Expenses and Other: | | | | |
| Other Operation and Maintenance | | | (41 | ) |
| Depreciation and Amortization | | | (7 | ) |
| Taxes Other Than Income Taxes | | | (12 | ) |
| Other Income | | | (2 | ) |
| Interest Expense | | | 2 | |
| Total Expenses and Other | | | (60 | ) |
| | | | | |
| Income Tax Expense | | | 12 | |
| | | | | |
| Year Ended December 31, 2010 | | $ | 230 | |
The major components of the increase in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:
| · | Retail Margins decreased $20 million due to: |
| | · | A $43 million decrease due to a refund provision for the 2009 Significantly Excessive Earnings Test (SEET). |
| | · | A $23 million decrease in capacity settlements under the Interconnection Agreement. |
| | · | A $16 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 partially included in Off-system Sales as margins are shared by the members of the AEP Power Pool. |
| | · | A $14 million decrease as a result of the elimination of Restructuring Transition Charge (RTC) revenues with the implementation of CSPCo’s ESP. |
| | These decreases were partially offset by: |
| | · | A $45 million increase in residential and commercial revenue from weather-related usage primarily due to a 54% increase in cooling degree days. |
| | · | A $26 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 $5 million increase related to the implementation of higher rates set by the Ohio ESP. |
| · | Margins from Off-system Sales increased $22 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 $41 million primarily due to: |
| | · | A $31 million increase due to expenses incurred related to cost reduction initiatives. In 2010, management conducted cost reduction initiatives to reduce both labor and non-labor expenses. | |
| | · | A $26 million increase in expenses due to the implementation of PUCO approved EE/PDR programs. This increase in Other Operation and Maintenance expenses was offset by a corresponding increase in Retail Margins as discussed above. | |
| | · | A $13 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: | |
| | · | An $8 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 approval of CSPCo’s ESP. | |
| | · | A $7 million decrease in steam plant removal expenses and a $3 million decrease in maintenance of electric plant expenses primarily related to work performed at the Conesville Plant in 2009. | |
| | · | A $7 million decrease in boiler plant maintenance expenses primarily related to work performed at the Conesville and Zimmer Plants in 2009. | |
| | · | A $3 million decrease in overhead distribution line expenses primarily due to ice and wind storms in the first quarter of 2009, partially offset by increased vegetation management activities. | |
| · | Depreciation and Amortization increased $7 million primarily due to environmental projects at the Conesville Plant that were completed and placed in service in November 2009. |
| · | Taxes Other Than Income Taxes increased $12 million primarily due to a $9 million increase in property taxes as a result of increased property values. |
| · | Income Tax Expense decreased $12 million primarily due to a decrease in pretax book income, changes in certain book/tax differences accounted for on a flow-through basis and a tax loss benefit from Parent, which was partially offset by federal income tax adjustments. |
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” beginning on page 405 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 Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 for a discussion of the adoption and impact of new accounting pronouncements.
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 405 for a discussion of risk management activities.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Columbus Southern Power Company:
We have audited the accompanying consolidated balance sheets of Columbus Southern Power Company and subsidiaries (the "Company") as of December 31, 2010 and 2009, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Columbus Southern Power Company and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Columbus, Ohio
February 25, 2011
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Columbus Southern Power Company and subsidiaries (CSPCo) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. CSPCo’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of CSPCo’s internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on management’s assessment, CSPCo’s internal control over financial reporting was effective as of December 31, 2010.
This annual report does not include an attestation report of CSPCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit CSPCo to provide only management’s report in this annual report.
| COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
| CONSOLIDATED STATEMENTS OF INCOME | |
| For the Years Ended December 31, 2010, 2009 and 2008 | |
| (in thousands) | |
| | |
| | | 2010 | | | 2009 | | | 2008 | |
| REVENUES | | | | | | | | | |
| Electric Generation, Transmission and Distribution | | $ | 2,063,255 | | | $ | 1,934,338 | | | $ | 2,079,610 | |
| Sales to AEP Affiliates | | | 82,994 | | | | 67,213 | | | | 122,949 | |
| Other Revenues | | | 2,792 | | | | 3,022 | | | | 5,542 | |
| TOTAL REVENUES | | | 2,149,041 | | | | 2,004,573 | | | | 2,208,101 | |
| | | | | | | | | | | | | |
| EXPENSES | | | | | | | | | | | | |
| Fuel and Other Consumables Used for Electric Generation | | | 399,886 | | | | 298,198 | | | | 360,792 | |
| Purchased Electricity for Resale | | | 106,114 | | | | 85,262 | | | | 197,943 | |
| Purchased Electricity from AEP Affiliates | | | 409,097 | | | | 392,761 | | | | 413,518 | |
| Other Operation | | | 350,047 | | | | 290,632 | | | | 348,051 | |
| Maintenance | | | 108,389 | | | | 126,441 | | | | 109,335 | |
| Depreciation and Amortization | | | 151,440 | | | | 144,402 | | | | 186,746 | |
| Taxes Other Than Income Taxes | | | 187,260 | | | | 175,151 | | | | 168,028 | |
| TOTAL EXPENSES | | | 1,712,233 | | | | 1,512,847 | | | | 1,784,413 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 436,808 | | | | 491,726 | | | | 423,688 | |
| | | | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | | | |
| Interest Income | | | 919 | | | | 802 | | | | 5,334 | |
| Carrying Costs Income | | | 8,166 | | | | 7,656 | | | | 6,551 | |
| Allowance for Equity Funds Used During Construction | | | 2,072 | | | | 3,382 | | | | 3,364 | |
| Interest Expense | | | (85,893 | ) | | | (88,184 | ) | | | (92,068 | ) |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAX EXPENSE | | | 362,072 | | | | 415,382 | | | | 346,869 | |
| | | | | | | | | | | | | |
| Income Tax Expense | | | 131,849 | | | | 143,721 | | | | 109,739 | |
| | | | | | | | | | | | | |
| NET INCOME | | | 230,223 | | | | 271,661 | | | | 237,130 | |
| | | | | | | | | | | | | |
| Capital Stock Expense | | | 149 | | | | 157 | | | | 157 | |
| | | | | | | | | | | | | |
| EARNINGS ATTRIBUTABLE TO COMMON STOCK | | $ | 230,074 | | | $ | 271,504 | | | $ | 236,973 | |
| | | | | | | | | | | | | |
| The common stock of CSPCo is wholly-owned by AEP. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
| COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S |
| EQUITY AND COMPREHENSIVE INCOME (LOSS) |
| For the Years Ended December 31, 2010, 2009 and 2008 |
| (in thousands) |
| |
| | | | | | | | Accumulated | | | |
| | | | | | | | | Other | | | |
| | | Common | | Paid-in | | Retained | | Comprehensive | | | |
| | | Stock | | Capital | | Earnings | | Income (Loss) | | | Total |
| TOTAL COMMON SHAREHOLDER'S EQUITY – | | | | | | | | | | | | | | | |
| | DECEMBER 31, 2007 | | $ | 41,026 | | $ | 580,349 | | $ | 561,696 | | $ | (18,794) | | $ | 1,164,277 |
| Adoption of Guidance for Split-Dollar Life Insurance | | | | | | | | | | | | | | | |
| | Accounting, Net of Tax of $589 | | | | | | | | | (1,095) | | | | | | (1,095) |
| Adoption of Guidance for Fair Value Accounting, | | | | | | | | | | | | | | | |
| | Net of Tax of $170 | | | | | | | | | (316) | | | | | | (316) |
| Common Stock Dividends | | | | | | | | | (122,500) | | | | | | (122,500) |
| Capital Stock Expense | | | | | | 157 | | | (157) | | | | | | - |
| SUBTOTAL – COMMON SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | 1,040,366 |
| | | | | | | | | | | | | | | | |
| COMPREHENSIVE INCOME | | | | | | | | | | | | | | | |
| Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | |
| | | Cash Flow Hedges, Net of Tax of $1,174 | | | | | | | | | | | | 2,181 | | | 2,181 |
| | | Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | |
| | | | Costs, Net of Tax of $607 | | | | | | | | | | | | 1,128 | | | 1,128 |
| | | Pension and OPEB Funded Status, Net of Tax of $19,137 | | | | | | | | | | | | (35,540) | | | (35,540) |
| NET INCOME | | | | | | | | | 237,130 | | | | | | 237,130 |
| TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 204,899 |
| 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 | | | | | | 157 | | | (157) | | | | | | - |
| 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 $1,027 | | | | | | | | | | | | (1,907) | | | (1,907) |
| | | Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | |
| | | | Costs, Net of Tax of $1,193 | | | | | | | | | | | | 2,215 | | | 2,215 |
| | | Pension and OPEB Funded Status, Net of Tax of $390 | | | | | | | | | | | | 724 | | | 724 |
| NET INCOME | | | | | | | | | 271,661 | | | | | | 271,661 |
| TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 272,693 |
| TOTAL COMMON SHAREHOLDER'S EQUITY – | | | | | | | | | | | | | | | |
| | DECEMBER 31, 2009 | | | 41,026 | | | 580,663 | | | 788,139 | | | (49,993) | | | 1,359,835 |
| | | | | | | | | | | | | | | | | | | |
| Common Stock Dividends | | | | | | | | | (102,500) | | | | | | (102,500) |
| Capital Stock Expense | | | | | | 149 | | | (149) | | | | | | - |
| SUBTOTAL – COMMON SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | 1,257,335 |
| | | | | | | | | | | | | | | | | | | |
| COMPREHENSIVE INCOME | | | | | | | | | | | | | | | |
| Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | |
| | | Cash Flow Hedges, Net of Tax of $130 | | | | | | | | | | | | 242 | | | 242 |
| | | Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | |
| | | | Costs, Net of Tax of $1,333 | | | | | | | | | | | | 2,475 | | | 2,475 |
| | | Pension and OPEB Funded Status, Net of Tax of $2,186 | | | | | | | | | | | | (4,060) | | | (4,060) |
| NET INCOME | | | | | | | | | 230,223 | | | | | | 230,223 |
| TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 228,880 |
| TOTAL COMMON SHAREHOLDER'S EQUITY – | | | | | | | | | | | | | | | |
| | DECEMBER 31, 2010 | | $ | 41,026 | | $ | 580,812 | | $ | 915,713 | | $ | (51,336) | | $ | 1,486,215 |
| | | | | | | | | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. |
| COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
| CONSOLIDATED BALANCE SHEETS | |
| ASSETS | |
| December 31, 2010 and 2009 | |
| (in thousands) | |
| | |
| | | 2010 | | | 2009 | |
| CURRENT ASSETS | | | | | | |
| Cash and Cash Equivalents | | $ | 509 | | | $ | 1,096 | |
| Other Cash Deposits | | | 2,260 | | | | 16,150 | |
| Advances to Affiliates | | | 54,202 | | | | - | |
| Accounts Receivable: | | | | | | | | |
| Customers | | | 50,187 | | | | 37,158 | |
| Affiliated Companies | | | 66,788 | | | | 28,555 | |
| Accrued Unbilled Revenues | | | 32,821 | | | | 11,845 | |
| Miscellaneous | | | 14,374 | | | | 4,164 | |
| Allowance for Uncollectible Accounts | | | (1,584 | ) | | | (3,481 | ) |
| Total Accounts Receivable | | | 162,586 | | | | 78,241 | |
| Fuel | | | 72,882 | | | | 74,158 | |
| Materials and Supplies | | | 42,033 | | | | 39,652 | |
| Emission Allowances | | | 28,486 | | | | 26,587 | |
| Risk Management Assets | | | 23,774 | | | | 34,343 | |
| Accrued Tax Benefits | | | 8,797 | | | | 29,273 | |
| Margin Deposits | | | 14,762 | | | | 14,874 | |
| Prepayments and Other Current Assets | | | 26,864 | | | | 6,349 | |
| TOTAL CURRENT ASSETS | | | 437,155 | | | | 320,723 | |
| | | | | | | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
| Electric: | | | | | | | | |
| Generation | | | 2,686,294 | | | | 2,641,860 | |
| Transmission | | | 662,312 | | | | 623,680 | |
| Distribution | | | 1,796,023 | | | | 1,745,559 | |
| Other Property, Plant and Equipment | | | 203,593 | | | | 189,315 | |
| Construction Work in Progress | | | 172,793 | | | | 155,081 | |
| Total Property, Plant and Equipment | | | 5,521,015 | | | | 5,355,495 | |
| Accumulated Depreciation and Amortization | | | 1,927,112 | | | | 1,838,840 | |
| TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 3,593,903 | | | | 3,516,655 | |
| | | | | | | | | |
| OTHER NONCURRENT ASSETS | | | | | | | | |
| Regulatory Assets | | | 298,111 | | | | 341,029 | |
| Long-term Risk Management Assets | | | 22,089 | | | | 23,882 | |
| Deferred Charges and Other Noncurrent Assets | | | 152,932 | | | | 147,217 | |
| TOTAL OTHER NONCURRENT ASSETS | | | 473,132 | | | | 512,128 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 4,504,190 | | | $ | 4,349,506 | |
| | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
| COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
| CONSOLIDATED BALANCE SHEETS | |
| LIABILITIES AND SHAREHOLDER'S EQUITY | |
| December 31, 2010 and 2009 | |
| | |
| | | 2010 | | | 2009 | |
| | | (in thousands) | |
| CURRENT LIABILITIES | | | | | | |
| Advances from Affiliates | | $ | - | | | $ | 24,202 | |
| Accounts Payable: | | | | | | | | |
| General | | | 98,925 | | | | 95,872 | |
| Affiliated Companies | | | 78,617 | | | | 81,338 | |
| Long-term Debt Due Within One Year – Nonaffiliated | | | - | | | | 150,000 | |
| Long-term Debt Due Within One Year – Affiliated | | | - | | | | 100,000 | |
| Risk Management Liabilities | | | 15,967 | | | | 13,052 | |
| Customer Deposits | | | 29,441 | | | | 27,911 | |
| Accrued Taxes | | | 226,572 | | | | 199,001 | |
| Accrued Interest | | | 22,533 | | | | 24,669 | |
| Other Current Liabilities | | | 111,868 | | | | 67,053 | |
| TOTAL CURRENT LIABILITIES | | | 583,923 | | | | 783,098 | |
| | | | | | | | | |
| NONCURRENT LIABILITIES | | | | | | | | |
| Long-term Debt – Nonaffiliated | | | 1,438,830 | | | | 1,286,393 | |
| Long-term Risk Management Liabilities | | | 6,223 | | | | 10,313 | |
| Deferred Income Taxes | | | 604,828 | | | | 535,265 | |
| Regulatory Liabilities and Deferred Investment Tax Credits | | | 163,888 | | | | 174,671 | |
| Employee Benefits and Pension Obligations | | | 136,643 | | | | 133,968 | |
| Deferred Credits and Other Noncurrent Liabilities | | | 83,640 | | | | 65,963 | |
| TOTAL NONCURRENT LIABILITIES | | | 2,434,052 | | | | 2,206,573 | |
| | | | | | | | | |
| TOTAL LIABILITIES | | | 3,017,975 | | | | 2,989,671 | |
| | | | | | | | | |
| Rate Matters (Note 4) | | | | | | | | |
| Commitments and Contingencies (Note 6) | | | | | | | | |
| | | | | | | | | |
| 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 | | | 580,812 | | | | 580,663 | |
| Retained Earnings | | | 915,713 | | | | 788,139 | |
| Accumulated Other Comprehensive Income (Loss) | | | (51,336 | ) | | | (49,993 | ) |
| TOTAL COMMON SHAREHOLDER’S EQUITY | | | 1,486,215 | | | | 1,359,835 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY | | $ | 4,504,190 | | | $ | 4,349,506 | |
| | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
| COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| For the Years Ended December 31, 2010, 2009 and 2008 | |
| (in thousands) | |
| | |
| | | 2010 | | | 2009 | | | 2008 | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net Income | | $ | 230,223 | | | $ | 271,661 | | | $ | 237,130 | |
| Adjustments to Reconcile Net Income to Net Cash Flows from | | | | | | | | | | | | |
| Operating Activities: | | | | | | | | | | | | |
| Depreciation and Amortization | | | 151,440 | | | | 144,402 | | | | 186,746 | |
| Deferred Income Taxes | | | 74,585 | | | | 131,407 | | | | (303 | ) |
| Carrying Costs Income | | | (8,166 | ) | | | (7,656 | ) | | | (6,551 | ) |
| Allowance for Equity Funds Used During Construction | | | (2,072 | ) | | | (3,382 | ) | | | (3,364 | ) |
| Mark-to-Market of Risk Management Contracts | | | 11,807 | | | | (4,786 | ) | | | (10,551 | ) |
| Property Taxes | | | (12,463 | ) | | | (7,364 | ) | | | (2,169 | ) |
| Fuel Over/Under-Recovery, Net | | | 21,792 | | | | (36,028 | ) | | | - | |
| Provision for 2009 Significantly Excessive Earnings Test | | | 42,683 | | | | - | | | | - | |
| Change in Other Noncurrent Assets | | | 596 | | | | (36,462 | ) | | | (8,984 | ) |
| Change in Other Noncurrent Liabilities | | | (17,655 | ) | | | 15,858 | | | | 12,254 | |
| Changes in Certain Components of Working Capital: | | | | | | | | | | | | |
| Accounts Receivable, Net | | | (75,580 | ) | | | 52,088 | | | | (14,976 | ) |
| Fuel, Materials and Supplies | | | 880 | | | | (37,954 | ) | | | (3,381 | ) |
| Accounts Payable | | | 17,209 | | | | (57,666 | ) | | | 67,349 | |
| Customer Deposits | | | 1,530 | | | | (2,234 | ) | | | (12,950 | ) |
| Accrued Taxes, Net | | | 43,965 | | | | (17,319 | ) | | | 5,075 | |
| Other Current Assets | | | 3,251 | | | | 9,439 | | | | (23,730 | ) |
| Other Current Liabilities | | | 5,867 | | | | (16,027 | ) | | | (8,241 | ) |
| Net Cash Flows from Operating Activities | | | 489,892 | | | | 397,977 | | | | 413,354 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction Expenditures | | | (235,901 | ) | | | (302,699 | ) | | | (433,014 | ) |
| Change in Other Cash Deposits | | | 13,890 | | | | 16,150 | | | | 21,460 | |
| Change in Advances to Affiliates, Net | | | (54,202 | ) | | | - | | | | - | |
| Acquisitions of Assets | | | (742 | ) | | | (232 | ) | | | (807 | ) |
| Proceeds from Sales of Assets | | | 5,106 | | | | 823 | | | | 1,576 | |
| Other Investing Activities | | | 12,667 | | | | - | | | | - | |
| Net Cash Flows Used for Investing Activities | | | (259,182 | ) | | | (285,958 | ) | | | (410,785 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Issuance of Long-term Debt - Nonaffiliated | | | 149,443 | | | | 91,160 | | | | 346,397 | |
| Change in Advances from Affiliates, Net | | | (24,202 | ) | | | (50,663 | ) | | | (20,334 | ) |
| Retirement of Long-term Debt - Nonaffiliated | | | (150,000 | ) | | | - | | | | (204,245 | ) |
| Retirement of Long-term Debt - Affiliated | | | (100,000 | ) | | | - | | | | - | |
| Principal Payments for Capital Lease Obligations | | | (4,170 | ) | | | (2,704 | ) | | | (2,936 | ) |
| Dividends Paid on Common Stock | | | (102,500 | ) | | | (150,000 | ) | | | (122,500 | ) |
| Other Financing Activities | | | 132 | | | | 221 | | | | 723 | |
| Net Cash Flows Used for Financing Activities | | | (231,297 | ) | | | (111,986 | ) | | | (2,895 | ) |
| | | | | | | | | | | | | |
| Net Increase (Decrease) in Cash and Cash Equivalents | | | (587 | ) | | | 33 | | | | (326 | ) |
| Cash and Cash Equivalents at Beginning of Period | | | 1,096 | | | | 1,063 | | | | 1,389 | |
| Cash and Cash Equivalents at End of Period | | $ | 509 | | | $ | 1,096 | | | $ | 1,063 | |
| | | | | | | | | | | | | |
| SUPPLEMENTARY INFORMATION | | | | | | | | | | | | |
| Cash Paid for Interest, Net of Capitalized Amounts | | $ | 85,240 | | | $ | 94,054 | | | $ | 78,539 | |
| Net Cash Paid for Income Taxes | | | 36,805 | | | | 46,945 | | | | 113,140 | |
| Noncash Acquisitions Under Capital Leases | | | 9,633 | | | | 892 | | | | 2,326 | |
| Government Grants Included in Accounts Receivable at December 31, | | | 9,260 | | | | - | | | | - | |
| Construction Expenditures Included in Accounts Payable at December 31, | | | 14,229 | | | | 31,106 | | | | 47,438 | |
| Noncash Dividend of Property to Parent | | | - | | | | 8,123 | | | | - | |
| SIA Refund Included in Accounts Payable at December 31, | | | - | | | | - | | | | 44,178 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The notes to CSPCo’s consolidated financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to CSPCo. The footnotes begin on page 246.
| | Footnote Reference |
| | |
| Organization and Summary of Significant Accounting Policies | Note 1 |
| New Accounting Pronouncements and Extraordinary Item | Note 2 |
| Rate Matters | Note 4 |
| Effects of Regulation | Note 5 |
| Commitments, Guarantees and Contingencies | Note 6 |
| Benefit Plans | Note 8 |
| Business Segments | Note 9 |
| Derivatives and Hedging | Note 10 |
| Fair Value Measurements | Note 11 |
| Income Taxes | Note 12 |
| Leases | Note 13 |
| Financing Activities | Note 14 |
| Related Party Transactions | Note 15 |
| Property, Plant and Equipment | Note 16 |
| Cost Reduction Initiatives | Note 17 |
| Unaudited Quarterly Financial Information | Note 18 |
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT’S NARRATIVE FINANCIAL DISCUSSION AND ANALYSIS
EXECUTIVE OVERVIEW
Company Overview
As a public utility, I&M engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 582,000 retail customers in its service territory in northern and eastern Indiana and a portion of southwestern Michigan. I&M consolidates Blackhawk Coal Company and Price River Coal Company, its wholly-owned subsidiaries. I&M also consolidates DCC Fuel. I&M sells power at wholesale to municipalities and electric cooperatives. I&M’s River Transportation Division (RTD) provides barging services to affiliates and nonaffiliated companies. The revenues from barging represent the majority of other revenues except in 2009 when insurance proceeds related to the Cook Plant Unit 1 outage were the largest amount .
Originally approved by the FERC in 1951 and subsequently amended in 1951, 1962, 1975, 1979 (twice) and 1980, the Interconnection Agreement establishes the AEP Power Pool which permits the AEP East companies to pool their generation assets on a cost basis. It establishes an allocation method for generating capacity among its members based on relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity revenues. AEP Power Pool members are compensated for their costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The capacity reserve relationship of the AEP Power Pool members changes as generating assets are added, retired or sold and relative peak demand changes. The AEP Power Pool calcula tes each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the MLR, which determines each member’s percentage share of revenues and costs.
In December 2010, each member gave notice to AEPSC and the other AEP Power Pool members of its decision to terminate the Interconnection Agreement effective January 1, 2014 or such other date approved by the FERC, subject to state regulatory input. It is unknown at this time whether the AEP 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 I&M experiences decreases in revenues or increases in costs as a result of the termination of the AEP Power Pool and is unable to recover the change in revenues and costs through rates, prices or additional sales, it could have an adverse impact on future net income and cash flows.
The AEP East companies are parties to a Transmission Agreement defining how they share the costs associated with their relative ownership of transmission assets. This sharing was based upon each company’s MLR until the FERC approved a new Transmission Agreement effective November 1, 2010. The new Transmission Agreement will be phased-in for retail rates over periods of up to four years, adds KGPCo and WPCo as parties to the agreement and changes the allocation method. I&M’s recovery mechanism for transmission costs is through its base rates. Changes in allocation under the new Transmission Agreement and state regulatory phase-in of the new agreement will limit I&M’s ability to fully recover its transmission costs.
Under unit power agreements, I&M purchases AEGCo’s 50% share of the 2,600 MW Rockport Plant capacity unless it is sold to other utilities. AEGCo is an affiliate that is not a member of the AEP Power Pool. An agreement between AEGCo and KPCo provides for the sale of 390 MW of AEGCo’s Rockport Plant capacity to KPCo through 2022. Therefore, I&M purchases 910 MW of AEGCo’s 50% share of Rockport Plant capacity.
Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and gas risk management activities based upon the location of such activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP generally accruing to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among the AEP East companies, PSO and SWEPCo in proportion to the marketing realization directly assigned to each zone for the current month plus the preceding eleven months.
AEPSC conducts power, gas, coal and emission allowance risk management activities on I&M’s behalf. I&M shares in the revenues and expenses associated with these risk management activities, as described in the preceding paragraph, with the other AEP East companies, PSO and SWEPCo. Power and gas risk management activities are allocated based on the existing power pool agreement and the SIA. I&M shares in coal and emission allowance risk management activities based on its proportion of fossil fuels burned by the AEP System. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas, coal and emission allowances. The electricity, gas, coal and emission all owance contracts include physical transactions, OTC options and financially-settled swaps and exchange-traded futures and options. AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts.
To minimize the credit requirements and operating constraints when operating within PJM, the AEP East companies as well as KGPCo and WPCo, agreed to a netting of all payment obligations incurred by any of the AEP East companies against all balances due to the AEP East companies, and to hold PJM harmless from actions that any one or more AEP East companies may take with respect to PJM.
I&M is jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to purchase power and sale activity pursuant to the SIA.
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 deferred in October 2010 and began amortizing in December 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. &# 160;See “Michigan Base Rate Filing” section of Note 4.
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. 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 ro tors 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 regulatory process or if any future regulatory proceedings are adverse, it could have an adverse impact on net income, cash flows and financial condition. See “Indiana Fuel Clause Filing” and “Michigan 2009 Power Supply Cost Recovery Reconciliation” sections of Note 4 and “Cook Plant Unit 1 Fire and Shutdown” section of Note 6.
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. 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 405 for additional discussion of relevant factors.
RESULTS OF OPERATIONS
KWH Sales/Degree Days
| Summary of KWH Energy Sales |
| | | | | | | | | | |
| | | Years Ended December 31, |
| | 2010 | | 2009 | | 2008 |
| | | (in millions of KWH) |
| Retail: | | | | | | | | |
| | Residential | | 6,083 | | | 5,767 | | | 6,059 |
| | Commercial | | 5,121 | | | 5,038 | | | 5,272 |
| | Industrial | | 7,445 | | | 6,762 | | | 7,536 |
| | Miscellaneous | | 72 | | | 76 | | | 76 |
| Total Retail | | 18,721 | | | 17,643 | | | 18,943 |
| | | | | | | | | |
| Wholesale | | 7,839 | | | 8,564 | | | 11,325 |
| | | | | | | | | |
| Total KWHs | | 26,560 | | | 26,207 | | | 30,268 |
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 |
| | | | | | | | | | | |
| | | | Years Ended December 31, |
| | | | 2010 | | 2009 | | 2008 |
| | | | (in degree days) |
| | | | | | | | | | | |
| | Actual - Heating (a) | | 3,759 | | | 3,876 | | | 4,146 |
| | Normal - Heating (b) | | 3,774 | | | 3,788 | | | 3,789 |
| | | | | | | | | | | |
| | Actual - Cooling (c) | | 1,165 | | | 580 | | | 747 |
| | Normal - Cooling (b) | | 832 | | | 844 | | | 842 |
| | | | | | | | | | | |
| | (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. |
| 2010 Compared to 2009 |
| | | | | |
| Reconciliation of Year Ended December 31, 2009 to Year Ended December 31, 2010 |
| Net Income |
| (in millions) |
| | | | | |
| Year Ended December 31, 2009 | | $ | 216 | |
| | | | | |
| Changes in Gross Margin: | | | | |
| Retail Margins | | | 171 | |
| FERC Municipals and Cooperatives | | | (32) | |
| Off-system Sales | | | 9 | |
| Transmission Revenues | | | 2 | |
| Other Revenues | | | (185) | |
| Total Change in Gross Margin | | | (35) | |
| | | | | |
| Total Expenses and Other: | | | | |
| Other Operation and Maintenance | | | (64) | |
| Depreciation and Amortization | | | (2) | |
| Taxes Other Than Income Taxes | | | (5) | |
| Other Income | | | 1 | |
| Interest Expense | | | (3) | |
| Total Expenses and Other | | | (73) | |
| | | | | |
| Income Tax Expense | | | 18 | |
| | | | | |
| Year Ended December 31, 2010 | | $ | 126 | |
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 $171 million primarily due to the following: |
| | · | An $87 million increase primarily due to a $78 million increase in fuel and purchased power costs recorded in 2009 related to the Cook Plant Unit 1 (Unit 1) shutdown. This increase was offset by a corresponding decrease in Other Revenues as discussed below. |
| | · | A $39 million increase in rate relief primarily due to the impact of the Michigan rate settlement approved in October 2010 and the approval of the Indiana base rate filing effective March 2009. This increase in Retail Margins had corresponding increases of $13 million related to riders/trackers recognized in expense items. |
| | · | A $38 million increase in weather-related usage and increased price for residential and commercial customers primarily due to an increase in cooling degree days. |
| | · | A $28 million increase in industrial sales margins due to higher usage in comparison to recessionary lows of 2009. |
| | These increases were partially offset by: |
| | · | A $15 million increase in PJM costs partially recovered through a rate rider included in the $13 million discussed above. |
| · | FERC Municipals and Cooperatives margins decreased $32 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 $185 million primarily due to the following: |
| | · | A $185 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 $78 million in 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 $9 million increase in 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 $64 million primarily due to the following: |
| | · | A $35 million increase due to expenses related to cost reduction initiatives. In 2010, management conducted cost reduction initiatives to reduce both labor and non-labor expenses. |
| | · | A $17 million increase in transmission expense primarily due to lower credits under the Transmission Agreement. |
| | · | A $9 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 decreased $18 million primarily due to a decrease 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. |
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” beginning on page 405 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 Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 for a discussion of the adoption and impact of new accounting pronouncements.
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 405 for a discussion of risk management activities.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Indiana Michigan Power Company:
We have audited the accompanying consolidated balance sheets of Indiana Michigan Power Company and subsidiaries (the "Company") as of December 31, 2010 and 2009, and the related consolidated statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Michigan Power Company and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Columbus, Ohio
February 25, 2011
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Indiana Michigan Power Company and subsidiaries (I&M) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. I&M’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of I&M’s internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on management’s assessment, I&M’s internal control over financial reporting was effective as of December 31, 2010.
This annual report does not include an attestation report of I&M’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit I&M to provide only management’s report in this annual report.
| INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
| CONSOLIDATED STATEMENTS OF INCOME | |
| For the Years Ended December 31, 2010, 2009 and 2008 | |
| (in thousands) | |
| | |
| | | 2010 | | | 2009 | | | 2008 | |
| REVENUES | | | | | | | | | |
| Electric Generation, Transmission and Distribution | | $ | 1,735,338 | | | $ | 1,685,308 | | | $ | 1,727,769 | |
| Sales to AEP Affiliates | | | 330,951 | | | | 196,151 | | | | 302,741 | |
| Other Revenues - Affiliated | | | 114,070 | | | | 110,143 | | | | 116,747 | |
| Other Revenues - Nonaffiliated | | | 15,368 | | | | 193,422 | | | | 19,102 | |
| TOTAL REVENUES | | | 2,195,727 | | | | 2,185,024 | | | | 2,166,359 | |
| | | | | | | | | | | | | |
| EXPENSES | | | | | | | | | | | | |
| Fuel and Other Consumables Used for Electric Generation | | | 465,482 | | | | 409,845 | | | | 436,078 | |
| Purchased Electricity for Resale | | | 128,369 | | | | 128,508 | | | | 116,958 | |
| Purchased Electricity from AEP Affiliates | | | 327,335 | | | | 337,308 | | | | 384,182 | |
| Other Operation | | | 560,346 | | | | 500,672 | | | | 527,669 | |
| Maintenance | | | 222,406 | | | | 218,036 | | | | 219,630 | |
| Depreciation and Amortization | | | 136,443 | | | | 134,690 | | | | 127,406 | |
| Taxes Other Than Income Taxes | | | 80,431 | | | | 75,262 | | | | 78,338 | |
| TOTAL EXPENSES | | | 1,920,812 | | | | 1,804,321 | | | | 1,890,261 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 274,915 | | | | 380,703 | | | | 276,098 | |
| | | | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | | | |
| Interest Income | | | 3,389 | | | | 5,776 | | | | 2,921 | |
| Allowance for Equity Funds Used During Construction | | | 15,678 | | | | 12,013 | | | | 965 | |
| Interest Expense | | | (104,465 | ) | | | (101,145 | ) | | | (89,851 | ) |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAX EXPENSE | | | 189,517 | | | | 297,347 | | | | 190,133 | |
| | | | | | | | | | | | | |
| Income Tax Expense | | | 63,426 | | | | 81,037 | | | | 58,258 | |
| | | | | | | | | | | | | |
| NET INCOME | | | 126,091 | | | | 216,310 | | | | 131,875 | |
| | | | | | | | | | | | | |
| Preferred Stock Dividend Requirements | | | 339 | | | | 339 | | | | 339 | |
| | | | | | | | | | | | | |
| EARNINGS ATTRIBUTABLE TO COMMON STOCK | | $ | 125,752 | | | $ | 215,971 | | | $ | 131,536 | |
| | | | | | | | | | | | | |
| The common stock of I&M is wholly-owned by AEP. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
| INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S |
| EQUITY AND COMPREHENSIVE INCOME (LOSS) |
| For the Years Ended December 31, 2010, 2009 and 2008 |
| (in thousands) |
| |
| | | | | | | | Accumulated | | | |
| | | | | | | | | Other | | | |
| | | Common | | Paid-in | | Retained | | Comprehensive | | | |
| | | Stock | | Capital | | Earnings | | Income (Loss) | | | Total |
| TOTAL COMMON SHAREHOLDER'S EQUITY – | | | | | | | | | | | | | | | |
| | DECEMBER 31, 2007 | | $ | 56,584 | | $ | 861,291 | | $ | 483,499 | | $ | (15,675) | | $ | 1,385,699 |
| | | | | | | | | | | | | | | | | | | |
| Adoption of Guidance for Split-Dollar Life Insurance | | | | | | | | | | | | | | | |
| | Accounting, Net of Tax of $753 | | | | | | | | | (1,398) | | | | | | (1,398) |
| Common Stock Dividends | | | | | | | | | (75,000) | | | | | | (75,000) |
| Preferred Stock Dividends | | | | | | | | | (339) | | | | | | (339) |
| SUBTOTAL – COMMON SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | 1,308,962 |
| | | | | | | | | | | | | | | | |
| COMPREHENSIVE INCOME | | | | | | | | | | | | | | | |
| Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | |
| | | Cash Flow Hedges, Net of Tax of $1,676 | | | | | | | | | | | | 3,112 | | | 3,112 |
| | | Amortization of Pension and OPEB Deferred Costs, Net | | | | | | | | | | | | | | | |
| | | | of Tax of $237 | | | | | | | | | | | | 441 | | | 441 |
| | | Pension and OPEB Funded Status, Net of Tax of $5,154 | | | | | | | | | | | | (9,572) | | | (9,572) |
| NET INCOME | | | | | | | | | 131,875 | | | | | | 131,875 |
| TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 125,856 |
| | | | | | | | | | | | | | | | | | | |
| 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 | | | | | | | | | (98,000) | | | | | | (98,000) |
| Preferred Stock Dividends | | | | | | | | | (339) | | | | | | (339) |
| Gain on Reacquired Preferred Stock | | | | | | 1 | | | | | | | | | 1 |
| SUBTOTAL – COMMON SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | 1,456,480 |
| | | | | | | | | | | | | | | | | | | |
| COMPREHENSIVE INCOME | | | | | | | | | | | | | | | |
| Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | |
| | | Cash Flow Hedges, Net of Tax of $462 | | | | | | | | | | | | (857) | | | (857) |
| | | Amortization of Pension and OPEB Deferred Costs, Net | | | | | | | | | | | | | | | |
| | | | of Tax of $445 | | | | | | | | | | | | 826 | | | 826 |
| | | Pension and OPEB Funded Status, Net of Tax of $13 | | | | | | | | | | | | 24 | | | 24 |
| NET INCOME | | | | | | | | | 216,310 | | | | | | 216,310 |
| TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 216,303 |
| | | | | | | | | | | | | | | | | | | |
| TOTAL COMMON SHAREHOLDER'S EQUITY – | | | | | | | | | | | | | | | |
| | DECEMBER 31, 2009 | | | 56,584 | �� | | 981,292 | | | 656,608 | | | (21,701) | | | 1,672,783 |
| | | | | | | | | | | | | | | | | | | |
| Common Stock Dividends | | | | | | | | | (105,000) | | | | | | (105,000) |
| Preferred Stock Dividends | | | | | | | | | (339) | | | | | | (339) |
| Gain on Reacquired Preferred Stock | | | | | | 2 | | | | | | | | | 2 |
| SUBTOTAL – COMMON SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | 1,567,446 |
| | | | | | | | | | | | | | | | | | | |
| COMPREHENSIVE INCOME | | | | | | | | | | | | | | | |
| Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | |
| | | Cash Flow Hedges, Net of Tax of $652 | | | | | | | | | | | | 1,211 | | | 1,211 |
| | | Amortization of Pension and OPEB Deferred | | | | | | | | | | | | | | | |
| | | | Costs, Net of Tax of $470 | | | | | | | | | | | | 873 | | | 873 |
| | | Pension and OPEB Funded Status, Net of Tax of $685 | | | | | | | | | | | | (1,272) | | | (1,272) |
| NET INCOME | | | | | | | | | 126,091 | | | | | | 126,091 |
| TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 126,903 |
| | | | | | | | | | | | | | | | | | | |
| TOTAL COMMON SHAREHOLDER'S EQUITY – | | | | | | | | | | | | | | | |
| | DECEMBER 31, 2010 | | $ | 56,584 | | $ | 981,294 | | $ | 677,360 | | $ | (20,889) | | $ | 1,694,349 |
| | | | | | | | | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. |
| INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
| CONSOLIDATED BALANCE SHEETS | |
| ASSETS | |
| December 31, 2010 and 2009 | |
| (in thousands) | |
| | |
| | | 2010 | | | 2009 | |
| CURRENT ASSETS | | | | | | |
| Cash and Cash Equivalents | | $ | 361 | | | $ | 779 | |
| Advances to Affiliates | | | - | | | | 114,012 | |
| Accounts Receivable: | | | | | | | | |
| Customers | | | 76,193 | | | | 71,120 | |
| Affiliated Companies | | | 149,169 | | | | 83,248 | |
| Accrued Unbilled Revenues | | | 19,449 | | | | 8,762 | |
| Miscellaneous | | | 10,968 | | | | 8,638 | |
| Allowance for Uncollectible Accounts | | | (1,692 | ) | | | (2,265 | ) |
| Total Accounts Receivable | | | 254,087 | | | | 169,503 | |
| Fuel | | | 87,551 | | | | 79,554 | |
| Materials and Supplies | | | 178,331 | | | | 164,439 | |
| Risk Management Assets | | | 27,526 | | | | 34,438 | |
| Accrued Tax Benefits | | | 71,113 | | | | 144,473 | |
| Deferred Cook Plant Fire Costs | | | 45,752 | | | | 134,322 | |
| Prepayments and Other Current Assets | | | 33,713 | | | | 29,395 | |
| TOTAL CURRENT ASSETS | | | 698,434 | | | | 870,915 | |
| | | | | | | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
| Electric: | | | | | | | | |
| Generation | | | 3,774,262 | | | | 3,634,215 | |
| Transmission | | | 1,188,665 | | | | 1,154,026 | |
| Distribution | | | 1,411,095 | | | | 1,360,553 | |
| Other Property, Plant and Equipment (including nuclear fuel and coal mining) | | | 719,708 | | | | 755,132 | |
| Construction Work in Progress | | | 301,534 | | | | 278,278 | |
| Total Property, Plant and Equipment | | | 7,395,264 | | | | 7,182,204 | |
| Accumulated Depreciation, Depletion and Amortization | | | 3,124,998 | | | | 3,073,695 | |
| TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 4,270,266 | | | | 4,108,509 | |
| | | | | | | | | |
| OTHER NONCURRENT ASSETS | | | | | | | | |
| Regulatory Assets | | | 556,254 | | | | 496,464 | |
| Spent Nuclear Fuel and Decommissioning Trusts | | | 1,515,227 | | | | 1,391,919 | |
| Long-term Risk Management Assets | | | 31,485 | | | | 29,134 | |
| Deferred Charges and Other Noncurrent Assets | | | 77,229 | | | | 82,047 | |
| TOTAL OTHER NONCURRENT ASSETS | | | 2,180,195 | | | | 1,999,564 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 7,148,895 | | | $ | 6,978,988 | |
| | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
| INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
| CONSOLIDATED BALANCE SHEETS | |
| LIABILITIES AND SHAREHOLDERS' EQUITY | |
| December 31, 2010 and 2009 | |
| | |
| | | 2010 | | | 2009 | |
| CURRENT LIABILITIES | | (in thousands) | |
| Advances from Affiliates | | $ | 42,769 | | | $ | - | |
| Accounts Payable: | | | | | | | | |
| General | | | 121,665 | | | | 171,192 | |
| Affiliated Companies | | | 105,221 | | | | 61,315 | |
| Long-term Debt Due Within One Year – Nonaffiliated | | | 154,457 | | | | 37,544 | |
| (December 31, 2010 amount includes $77,457 related to DCC Fuel) | | | | | | | | |
| Long-term Debt Due Within One Year – Affiliated | | | - | | | | 25,000 | |
| Risk Management Liabilities | | | 16,785 | | | | 13,436 | |
| Customer Deposits | | | 29,264 | | | | 27,711 | |
| Accrued Taxes | | | 62,637 | | | | 56,814 | |
| Accrued Interest | | | 27,444 | | | | 27,633 | |
| Other Current Liabilities | | | 140,710 | | | | 151,865 | |
| TOTAL CURRENT LIABILITIES | | | 700,952 | | | | 572,510 | |
| | | | | | | | | |
| NONCURRENT LIABILITIES | | | | | | | | |
| Long-term Debt – Nonaffiliated | | | 1,849,769 | | | | 2,015,362 | |
| Long-term Risk Management Liabilities | | | 6,530 | | | | 10,386 | |
| Deferred Income Taxes | | | 760,105 | | | | 696,163 | |
| Regulatory Liabilities and Deferred Investment Tax Credits | | | 852,197 | | | | 756,845 | |
| Asset Retirement Obligations | | | 963,029 | | | | 894,746 | |
| Deferred Credits and Other Noncurrent Liabilities | | | 313,892 | | | | 352,116 | |
| TOTAL NONCURRENT LIABILITIES | | | 4,745,522 | | | | 4,725,618 | |
| | | | | | | | | |
| TOTAL LIABILITIES | | | 5,446,474 | | | | 5,298,128 | |
| | | | | | | | | |
| Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 8,072 | | | | 8,077 | |
| | | | | | | | | |
| Rate Matters (Note 4) | | | | | | | | |
| Commitments and Contingencies (Note 6) | | | | | | | | |
| | | | | | | | | |
| 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 | | | | 981,292 | |
| Retained Earnings | | | 677,360 | | | | 656,608 | |
| Accumulated Other Comprehensive Income (Loss) | | | (20,889 | ) | | | (21,701 | ) |
| TOTAL COMMON SHAREHOLDER’S EQUITY | | | 1,694,349 | | | | 1,672,783 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 7,148,895 | | | $ | 6,978,988 | |
| | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
| INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| For the Years Ended December 31, 2010, 2009 and 2008 | |
| (in thousands) | |
| | |
| | | 2010 | | | 2009 | | | 2008 | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net Income | | $ | 126,091 | | | $ | 216,310 | | | $ | 131,875 | |
| Adjustments to Reconcile Net Income to Net Cash Flows from | | | | | | | | | | | | |
| Operating Activities: | | | | | | | | | | | | |
| Depreciation and Amortization | | | 136,443 | | | | 134,690 | | | | 127,406 | |
| Accretion of Asset Retirement Obligations | | | 11,905 | | | | 11,178 | | | | 21,178 | |
| Deferred Income Taxes | | | 63,947 | | | | 271,264 | | | | 57,879 | |
| Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net | | | (31,939 | ) | | | 3,110 | | | | 8,925 | |
| Allowance for Equity Funds Used During Construction | | | (15,678 | ) | | | (12,013 | ) | | | (965 | ) |
| Mark-to-Market of Risk Management Contracts | | | 4,592 | | | | (10,533 | ) | | | (10,482 | ) |
| Amortization of Nuclear Fuel | | | 139,438 | | | | 62,699 | | | | 87,574 | |
| Pension Contributions to Qualified Plan Trust | | | (71,681 | ) | | | - | | | | - | |
| Fuel Over/Under Recovery, Net | | | (12,589 | ) | | | 34,676 | | | | (35,688 | ) |
| Change in Other Noncurrent Assets | | | (12,597 | ) | | | (16,555 | ) | | | (9,533 | ) |
| Change in Other Noncurrent Liabilities | | | 56,592 | | | | 45,276 | | | | 45,073 | |
| Changes in Certain Components of Working Capital: | | | | | | | | | | | | |
| Accounts Receivable, Net | | | (85,072 | ) | | | 19,338 | | | | (3,753 | ) |
| Fuel, Materials and Supplies | | | (16,564 | ) | | | (20,676 | ) | | | (7,822 | ) |
| Accounts Payable | | | 46,579 | | | | (65,424 | ) | | | 90,041 | |
| Accrued Taxes, Net | | | 77,075 | | | | (132,214 | ) | | | 6,283 | |
| Received (Deferred) Cook Plant Fire Costs, Net | | | 87,347 | | | | (89,409 | ) | | | (23,013 | ) |
| Other Current Assets | | | 5,056 | | | | (5,351 | ) | | | (8,966 | ) |
| Other Current Liabilities | | | 4,149 | | | | (2,924 | ) | | | 15,351 | |
| Net Cash Flows from Operating Activities | | | 513,094 | | | | 443,442 | | | | 491,363 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction Expenditures | | | (333,238 | ) | | | (332,775 | ) | | | (352,335 | ) |
| Change in Advances to Affiliates, Net | | | 114,012 | | | | (114,012 | ) | | | - | |
| Purchases of Investment Securities | | | (1,414,473 | ) | | | (770,919 | ) | | | (803,664 | ) |
| Sales of Investment Securities | | | 1,361,813 | | | | 712,742 | | | | 732,475 | |
| Acquisitions of Nuclear Fuel | | | (90,903 | ) | | | (169,138 | ) | | | (192,299 | ) |
| Other Investing Activities | | | 17,105 | | | | 21,004 | | | | 3,642 | |
| Net Cash Flows Used for Investing Activities | | | (345,684 | ) | | | (653,098 | ) | | | (612,181 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Capital Contribution from Parent | | | - | | | | 120,000 | | | | - | |
| Issuance of Long-term Debt - Nonaffiliated | | | 152,464 | | | | 670,060 | | | | 115,269 | |
| Issuance of Long-term Debt - Affiliated | | | - | | | | 25,000 | | | | - | |
| Change in Advances from Affiliates, Net | | | 42,769 | | | | (476,036 | ) | | | 430,972 | |
| Retirement of Long-term Debt - Nonaffiliated | | | (202,011 | ) | | | - | | | | (312,000 | ) |
| Retirement of Long-term Debt - Affiliated | | | (25,000 | ) | | | - | | | | - | |
| Retirement of Cumulative Preferred Stock | | | (3 | ) | | | (2 | ) | | | - | |
| Principal Payments for Capital Lease Obligations | | | (31,180 | ) | | | (31,637 | ) | | | (39,427 | ) |
| Dividends Paid on Common Stock | | | (105,000 | ) | | | (98,000 | ) | | | (75,000 | ) |
| Dividends Paid on Cumulative Preferred Stock | | | (339 | ) | | | (339 | ) | | | (339 | ) |
| Other Financing Activities | | | 472 | | | | 661 | | | | 932 | |
| Net Cash Flows from (Used for) Financing Activities | | | (167,828 | ) | | | 209,707 | | | | 120,407 | |
| | | | | | | | | | | | | |
| Net Increase (Decrease) in Cash and Cash Equivalents | | | (418 | ) | | | 51 | | | | (411 | ) |
| Cash and Cash Equivalents at Beginning of Period | | | 779 | | | | 728 | | | | 1,139 | |
| Cash and Cash Equivalents at End of Period | | $ | 361 | | | $ | 779 | | | $ | 728 | |
| | | | | | | | | | | | | |
| SUPPLEMENTARY INFORMATION | | | | | | | | | | | | |
| Cash Paid for Interest, Net of Capitalized Amounts | | $ | 100,617 | | | $ | 99,079 | | | $ | 75,981 | |
| Net Cash Paid (Received) for Income Taxes | | | (71,268 | ) | | | (51,298 | ) | | | 310 | |
| Noncash Acquisitions Under Capital Leases | | | 10,000 | | | | 2,651 | | | | 4,472 | |
| Construction Expenditures Included in Accounts Payable at December 31, | | | 21,757 | | | | 74,251 | | | | 50,507 | |
| Acquisition of Nuclear Fuel Included in Accounts Payable at December 31, | | | 308 | | | | 15 | | | | 37,628 | |
| SIA Refund Included in Accounts Payable at December 31, | | | - | | | | - | | | | 48,489 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The notes to I&M’s consolidated financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to I&M. The footnotes begin on page 246.
| | Footnote Reference |
| | |
| Organization and Summary of Significant Accounting Policies | Note 1 |
| New Accounting Pronouncements and Extraordinary Item | Note 2 |
| Rate Matters | Note 4 |
| Effects of Regulation | Note 5 |
| Commitments, Guarantees and Contingencies | Note 6 |
| Benefit Plans | Note 8 |
| Business Segments | Note 9 |
| Derivatives and Hedging | Note 10 |
| Fair Value Measurements | Note 11 |
| Income Taxes | Note 12 |
| Leases | Note 13 |
| Financing Activities | Note 14 |
| Related Party Transactions | Note 15 |
| Property, Plant and Equipment | Note 16 |
| Cost Reduction Initiatives | Note 17 |
| Unaudited Quarterly Financial Information | Note 18 |
OHIO POWER COMPANY CONSOLIDATED
| OHIO POWER COMPANY CONSOLIDATED |
| SELECTED CONSOLIDATED FINANCIAL DATA |
| (in thousands) |
| |
| | | | | 2010 | | 2009 | | 2008 | | 2007 | | 2006 |
| STATEMENTS OF INCOME DATA | | | | | | | | | | | | | | | |
| Total Revenues | | $ | 3,223,707 | | $ | 3,011,574 | | $ | 3,096,934 | | $ | 2,814,212 | | $ | 2,724,875 |
| | | | | | | | | | | | | | | | | | |
| Operating Income | | $ | 607,802 | | $ | 613,193 | | $ | 495,050 | | $ | 526,352 | | $ | 425,291 |
| | | | | | | | | | | | | | | | | | |
| Net Income | | $ | 311,393 | | $ | 308,615 | | $ | 232,455 | | $ | 271,186 | | $ | 231,434 |
| Less: Net Income Attributable to | | | | | | | | | | | | | | | |
| | Noncontrolling Interest | | | - | | | 2,042 | | | 1,332 | | | 2,622 | | | 2,791 |
| Net Income Attributable to OPCo | | | | | | | | | | | | | | | |
| | Shareholders | | | 311,393 | | | 306,573 | | | 231,123 | | | 268,564 | | | 228,643 |
| Less: Preferred Stock Dividend | | | | | | | | | | | | | | | |
| | Requirements | | | 732 | | | 732 | | | 732 | | | 732 | | | 732 |
| Earnings Attributable to OPCo Common | | | | | | | | | | | | | | | |
| | Shareholder | | $ | 310,661 | | $ | 305,841 | | $ | 230,391 | | $ | 267,832 | | $ | 227,911 |
| | | | | | | | | | | | | | | | | | |
| BALANCE SHEETS DATA | | | | | | | | | | | | | | | |
| Total Property, Plant and Equipment | | $ | 10,263,541 | | $ | 10,013,458 | | $ | 9,788,862 | | $ | 9,140,357 | | $ | 8,405,645 |
| Accumulated Depreciation and Amortization | | | 3,606,777 | | | 3,318,896 | | | 3,122,989 | | | 2,967,285 | | | 2,836,584 |
| Total Property, Plant and Equipment – Net | | $ | 6,656,764 | | $ | 6,694,562 | | $ | 6,665,873 | | $ | 6,173,072 | | $ | 5,569,061 |
| | | | | | | | | | | | | | | | | | |
| Total Assets | | $ | 8,747,327 | | $ | 9,039,139 | | $ | 8,003,826 | | $ | 7,338,429 | | $ | 6,807,528 |
| | | | | | | | | | | | | | | | | | |
| Total Common Shareholder's Equity | | $ | 3,168,424 | | $ | 3,234,695 | | $ | 2,421,945 | | $ | 2,291,017 | | $ | 2,008,342 |
| | | | | | | | | | | | | | | | | | |
| Cumulative Preferred Stock Not Subject to | | | | | | | | | | | | | | | |
| | Mandatory Redemption | | $ | 16,616 | | $ | 16,627 | | $ | 16,627 | | $ | 16,627 | | $ | 16,630 |
| | | | | | | | | | | | | | | | | | |
| Noncontrolling Interest | | $ | - | | $ | - | | $ | 16,799 | | $ | 15,923 | | $ | 15,825 |
| | | | | | | | | | | | | | | | | | |
| Long-term Debt (a) | | $ | 2,729,522 | | $ | 3,242,505 | | $ | 3,039,376 | | $ | 2,849,598 | | $ | 2,401,741 |
| | | | | | | | | | | | | | | | | | |
| Obligations Under Capital Leases (a) | | $ | 50,307 | (b) | $ | 22,682 | | $ | 26,466 | | $ | 29,077 | | $ | 34,966 |
| | | | | | | | | | | | | | | | | | |
| (a) | Includes portion due within one year. |
| (b) | Obligations Under Capital Leases increased primarily due to capital leases under new master lease agreements for property |
| | | that was previously leased under operating leases. |
OHIO POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
EXECUTIVE OVERVIEW
Company Overview
As a public utility, OPCo engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to 706,000 retail customers in the northwestern, east central, eastern and southern sections of Ohio. OPCo consolidated JMG Funding LP, a variable interest entity, until it was dissolved in December 2009 at which time JMG’s assets were transferred to OPCo. This change had an immaterial impact on comparative financial statements.
In October 2010, CSPCo and OPCo filed with the PUCO to merge CSPCo into OPCo. Approval of the merger will not affect CSPCo's and OPCo's rates until the PUCO approves new rates, terms and conditions for the merged company. In January 2011, CSPCo and OPCo filed with the FERC requesting approval for an internal corporate reorganization under which CSPCo will merge into OPCo effective October 2011.
Originally approved by the FERC in 1951 and subsequently amended in 1951, 1962, 1975, 1979 (twice) and 1980, the Interconnection Agreement establishes the AEP Power Pool which permits the AEP East companies to pool their generation assets on a cost basis. It establishes an allocation method for generating capacity among its members based on relative peak demands and generating reserves through the payment of capacity charges and the receipt of capacity revenues. AEP Power Pool members are compensated for their costs of energy delivered to the AEP Power Pool and charged for energy received from the AEP Power Pool. The capacity reserve relationship of the AEP Power Pool members changes as generating assets are added, retired or sold and relative peak demand changes. The AEP Power Pool calcula tes each member’s prior twelve-month peak demand relative to the sum of the peak demands of all members as a basis for sharing revenues and costs. The result of this calculation is the MLR, which determines each member’s percentage share of revenues and costs.
In December 2010, each member gave notice to AEPSC and the other AEP Power Pool members of its decision to terminate the Interconnection Agreement effective January 1, 2014 or such other date approved by the FERC, subject to state regulatory input. It is unknown at this time whether the AEP 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 OPCo experiences decreases in revenues or increases in costs as a result of the termination of the AEP Power Pool and is unable to recover the change in revenues and costs through rates, prices or additional sales, it could have an adverse impact on future net income and cash flows.
The AEP East companies are parties to a Transmission Agreement defining how they share the costs associated with their relative ownership of transmission assets. This sharing was based upon each company’s MLR until the FERC approved a new Transmission Agreement effective November 1, 2010. The impacts of the new Transmission Agreement will be phased-in for retail rates, adds KGPCo and WPCo as parties to the agreement and changes the allocation method.
Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and gas risk management activities based upon the location of such activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP generally accruing to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among the AEP East companies, PSO and SWEPCo in proportion to the marketing realization directly assigned to each zone for the current month plus the preceding eleven months.
AEPSC conducts power, gas, coal and emission allowance risk management activities on OPCo’s behalf. OPCo shares in the revenues and expenses associated with these risk management activities, as described in the preceding paragraph, with the other AEP East companies, PSO and SWEPCo. Power and gas risk management activities are allocated based on the existing power pool agreement and the SIA. OPCo shares in coal and emission allowance
risk management activities based on its proportion of fossil fuels burned by the AEP System. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas, coal and emission allowances. The electricity, gas, coal and emission allowance contracts include physical transactions, OTC options and financially-settled swaps and exchange-traded futures and options. AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts.
To minimize the credit requirements and operating constraints of operating within PJM, the AEP East companies as well as KGPCo and WPCo, agreed to a netting of all payment obligations incurred by any of the AEP East companies against all balances due to the AEP East companies, and to hold PJM harmless from actions that any one or more AEP East companies may take with respect to PJM.
OPCo is jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to purchase power and sale activity pursuant to the SIA.
Regulatory Activity
2009 – 2011 ESP
During 2009, the PUCO issued an order that modified and approved OPCo’s ESP which established rates through 2011. The order also limited annual rate increases for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011. The order provided 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. In January 2011, the PUCO issued an order that determined that OPCo’s 2009 earnings were not significantly excessive. See “Ohio Electric Security Plan Filings” section of Note 4.
Proposed 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 individually vary, but on average, customers will experience net base generation increases of 1.4% in 2012 and 2.7% for the period January 2013 through May 2014. See “Ohio Electric Security Plan Filings” section of Note 4.
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. 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 405 for additional discussion of relevant factors.
RESULTS OF OPERATIONS
KWH Sales/Degree Days
| Summary of KWH Energy Sales |
| | | | | | | | | | |
| | | Years Ended December 31, |
| | 2010 | | 2009 | | 2008 |
| | | (in millions of KWH) |
| Retail: | | | | | | | | |
| | Residential | | 7,582 | | | 7,339 | | | 7,528 |
| | Commercial | | 5,745 | | | 5,686 | | | 5,824 |
| | Industrial | | 12,800 | | | 11,834 | | | 14,441 |
| | Miscellaneous | | 73 | | | 77 | | | 79 |
| Total Retail | | 26,200 | | | 24,936 | | | 27,872 |
| | | | | | | | | |
| Wholesale | | 5,516 | | | 4,136 | | | 7,384 |
| | | | | | | | | |
| Total KWHs | | 31,716 | | | 29,072 | | | 35,256 |
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 |
| | | | | | | | | | | |
| | | | Years Ended December 31, |
| | | | 2010 | | 2009 | | 2008 |
| | | | (in degree days) |
| | | | | | | | | | | |
| | Actual - Heating (a) | | 3,714 | | | 3,682 | | | 3,845 |
| | Normal - Heating (b) | | 3,536 | | | 3,545 | | | 3,535 |
| | | | | | | | | | | |
| | Actual - Cooling (c) | | 1,040 | | | 566 | | | 700 |
| | Normal - Cooling (b) | | 795 | | | 807 | | | 813 |
| | | | | | | | | | | |
| | (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. |
| 2010 Compared to 2009 | |
| | | | |
| Reconciliation of Year Ended December 31, 2009 to Year Ended December 31, 2010 | |
| Net Income | |
| (in millions) | |
| | | | |
| Year Ended December 31, 2009 | | $ | 309 | |
| | | | | |
| Changes in Gross Margin: | | | | |
| Retail Margins | | | 92 | |
| Off-system Sales | | | 19 | |
| Transmission Revenues | | | 1 | |
| Other Revenues | | | (22 | ) |
| Total Change in Gross Margin | | | 90 | |
| | | | | |
| Total Expenses and Other: | | | | |
| Other Operation and Maintenance | | | (74 | ) |
| Depreciation and Amortization | | | (10 | ) |
| Taxes Other Than Income Taxes | | | (12 | ) |
| Carrying Costs Income | | | 13 | |
| Other Income | | | 1 | |
| Interest Expense | | | (3 | ) |
| Total Expenses and Other | | | (85 | ) |
| | | | | |
| Income Tax Expense | | | (3 | ) |
| | | | | |
| Year Ended December 31, 2010 | | $ | 311 | |
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 $92 million primarily due to the following: |
| | · | A $37 million increase in retail sales as a result of an increase in weather-related usage by residential and commercial customers primarily due to an 84% increase in cooling degree days and increased usage by industrial customers in comparison to recessionary lows in 2009. |
| | · | A $37 million increase in capacity settlements under the Interconnection Agreement. |
| | · | A $29 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 $25 million FERC approved increase in demand charges received from WPCo effective January 2010. |
| | These increases were partially offset by: |
| | · | A $10 million decrease related to increased consumable and allowance expenses. |
| | · | A $9 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. |
| · | Margins from Off-system Sales increased $19 million primarily due to increased prices and higher physical sales volumes, partially offset by lower trading and marketing margins. |
| · | Other Revenues decreased $22 million primarily due to reduced gains on sales of emission allowances as a result of lower market prices for allowances. Gains on sales of allowances are partially offset by sharing in the fuel clause. |
Total Expenses and Other and Income Tax Expense changed between years as follows:
| · | Other Operation and Maintenance expenses increased $74 million primarily due to: |
| | · | A $54 million increase in expenses related to cost reduction initiatives. In 2010, management conducted cost reduction initiatives to reduce both labor and non-labor expenses. |
| | · | A $29 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 $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: |
| | · | An $11 million decrease related to a 2009 coal blending project. |
| | · | A $5 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 approval of OPCo’s ESP. |
| · | Depreciation and Amortization increased $10 million primarily due to: |
| | · | A $13 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 $3 million decrease primarily due to the completion of the amortization of software in the fourth quarter of 2009. |
| · | Taxes Other Than Income Taxes increased $12 million primarily due to: |
| | · · · | An $8 million increase in real and property taxes. A $3 million increase in state excise taxes. A $2 million increase due to the employer portion of payroll taxes incurred related to cost reduction initiatives. |
| · | Carrying Costs Income increased $13 million primarily due to a higher under-recovered fuel balance in 2010. |
| · | Income Tax Expense increased $3 million primarily due to an increase in pretax book income, the recording of federal income tax adjustments and the tax treatment associated with the future reimbursement of Medicare Part D retiree prescription drug benefits, partially offset by the regulatory accounting treatment of state income taxes. |
| 2009 Compared to 2008 | |
| | | | |
| Reconciliation of Year Ended December 31, 2008 to Year Ended December 31, 2009 | |
| Net Income | |
| (in millions) | |
| | | | |
| Year Ended December 31, 2008 | | $ | 232 | |
| | | | | |
| Changes in Gross Margin: | | | | |
| Retail Margins | | | 283 | |
| Off-system Sales | | | (119 | ) |
| Transmission Revenues | | | (1 | ) |
| Other Revenues | | | 17 | |
| Total Change in Gross Margin | | | 180 | |
| | | | | |
| Total Expenses and Other: | | | | |
| Other Operation and Maintenance | | | 18 | |
| Depreciation and Amortization | | | (78 | ) |
| Taxes Other Than Income Taxes | | | (2 | ) |
| Carrying Costs Income | | | (6 | ) |
| Other Income | | | (5 | ) |
| Interest Expense | | | 21 | |
| Total Expenses and Other | | | (52 | ) |
| | | | | |
| Income Tax Expense | | | (51 | ) |
| | | | | |
| Year Ended December 31, 2009 | | $ | 309 | |
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 $283 million primarily due to the following: |
| | · | A $148 million increase related to the implementation of higher rates set by the Ohio ESP. |
| | · | A $142 million increase in fuel margins primarily due to the deferral of fuel costs in 2009. The PUCO’s March 2009 approval of OPCo’s ESP allows for the deferral of fuel and related costs incurred during the ESP period. |
| | · | A $61 million increase in capacity settlements under the Interconnection Agreement. |
| | · | A $42 million increase due to the December 2008 provision for refund of off-system sales margins as ordered by the FERC related to the SIA. |
| | These increases were partially offset by: |
| | · | An $86 million decrease in industrial sales due to reduced operating levels and suspended operations by certain large industrial customers in OPCo’s service territory. |
| | · | A $29 million decrease related to coal contract amendments recorded in 2008. |
| · | Margins from Off-system Sales decreased $119 million primarily due to lower physical sales volumes and lower margins as a result of lower market prices, partially offset by higher trading and marketing margins. |
| · | Other Revenues increased $17 million primarily due to net 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 $18 million primarily due to: |
| | · | A $13 million decrease in removal and plant maintenance expenses from a reduction in planned and forced outages at various plants during 2009. During 2008, the precipitator upgrade and boiler overhauls at Amos Plant had increased expense. |
| | · | A $9 million decrease in employee benefit expenses. |
| | · | A $9 million decrease in recoverable PJM expenses. |
| | · | An $8 million decrease in recoverable customer account expenses due to decreased Universal Service Fund surcharge rates for customers who qualify for payment assistance. |
| | · | A $5 million decrease in transmission expenses related to the AEP Transmission Equalization Agreement. |
| | These decreases were partially offset by: |
| | · | A $19 million increase in maintenance of overhead lines primarily due to an increase in vegetation management activities. |
| | · | An $11 million increase relating to a coal blending project. |
| · | Depreciation and Amortization increased $78 million primarily due to: |
| | · | An $82 million increase from higher depreciable property balances as a result of environmental improvements placed in service and various other property additions and higher depreciation rates related to shortened depreciable lives for certain generating facilities. |
| | · | A $22 million increase due to the completion of the amortization of a regulatory liability in December 2008 related to energy sales to Ormet at below market rates. |
| | These increases were partially offset by: |
| | · | A $28 million decrease due to the completion of the amortization of regulatory assets in December 2008. |
| · | Interest Expense decreased $21 million primarily due to: |
| | · | A $20 million decrease in interest expense primarily related to the December 2008 provision for refund of off-system sales margins in accordance with FERC’s order related to the SIA. |
| | · | A $7 million decrease in interest expense related to the reacquisition of JMG’s bonds during the third quarter of 2009 at lower interest rates. |
| | · | A $7 million decrease in interest expense primarily due to an unrealized gain on an interest rate hedge of a forecasted debt issuance. |
| | These decreases were partially offset by: |
| | · | A $15 million increase primarily related to a decrease in the debt component of AFUDC as a result of the Amos Plant FGD and precipitator upgrade going into service in the first quarter of 2009. |
| · | Income Tax Expense increased $51 million primarily due to an increase in pretax book income. |
FINANCIAL CONDITION
LIQUIDITY
OPCo participates in the Utility Money Pool, which provides access to AEP’s liquidity. OPCo 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 405 for additional discussion of liquidity.
Credit Ratings
OPCo’s ultimate access to capital markets may depend on its credit ratings. In addition, a credit rating downgrade of OPCo by one of the rating agencies could increase OPCo’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 2010, 2009 and 2008 were as follows:
| | | Years Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (in thousands) | |
| Cash and Cash Equivalents at Beginning of Period | | $ | 1,984 | | | $ | 12,679 | | | $ | 6,666 | |
| Cash Flows from (Used for): | | | | | | | | | | | | |
| Operating Activities | | | 821,807 | | | | 321,034 | | | | 485,877 | |
| Investing Activities | | | 73,112 | | | | (812,981 | ) | | | (701,789 | ) |
| Financing Activities | | | (896,463 | ) | | | 481,252 | | | | 221,925 | |
| Net Increase (Decrease) in Cash and Cash Equivalents | | | (1,544 | ) | | | (10,695 | ) | | | 6,013 | |
| Cash and Cash Equivalents at End of Period | | $ | 440 | | | $ | 1,984 | | | $ | 12,679 | |
Operating Activities
Net Cash Flows from Operating Activities were $822 million in 2010. OPCo produced Net Income of $311 million during the period and noncash expense items of $362 million for Depreciation and Amortization and $218 million for Deferred Income Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in working capital relates to a number of items. Accrued Taxes, Net had an $87 million inflow due to a 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. Fu el, Materials and Supplies had a $65 million inflow primarily due to a decrease in coal inventory to target levels as well as price decreases due to the expiration of higher priced spot market contracts. The $154 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.
Net Cash Flows from Operating Activities were $321 million in 2009. OPCo produced Net Income of $309 million during the period and noncash expense items of $352 million for Depreciation and Amortization and $383 million for Deferred Income Taxes. The $383 million inflow for Deferred Income Taxes was 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. 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 per iod activity in working capital primarily relates to a number of items. Fuel, Materials and Supplies had a $156 million outflow primarily due to an increase in coal inventory reflecting decreased customer demand for electricity. Accounts Payable had a $121 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 $119 million outflow due to an increase in accrued tax benefits resulting from a net income tax operating loss in 2009. The $298 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.
Net Cash Flows from Operating Activities were $486 million in 2008. OPCo produced Net Income of $232 million during the period and a noncash expense item of $274 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 and changes in the 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. Accounts Payable had a $127 million inflow due to increases in tonnage and prices per ton related to fuel and consumable purchases and also included OPCo’s December 2008 provision for refund of $62 million which was paid in the first quarter of 2009 to the AEP West companie s as part of the FERC’s order on the SIA. Fuel, Materials and Supplies had an $89 million outflow due to price increases.
Investing Activities
Net Cash Flows from Investing Activities were $73 million in 2010. Net Cash Flows Used for Investing Activities were $813 million in 2009 and $702 million in 2008. OPCo had a net decrease of $338 million and a net increase of $438 million in loans to the Utility Money Pool during 2010 and 2009, respectively. Construction Expenditures of $277 million, $418 million and $706 million in 2010, 2009 and 2008, respectively, were primarily related to environmental upgrades and projects to improve service reliability for transmission and distribution. Environmental upgrades include the installation of FGD projects at the Amos and Cardinal Plants.
Financing Activities
Net Cash Flows Used for Financing Activities were $896 million in 2010. OPCo retired $600 million of Senior Unsecured Notes and $118 million of Pollution Control Bonds. In addition, OPCo paid $367 million of dividends on common stock. These decreases were partially offset by the issuance of $204 million of Pollution Control Bonds.
Net Cash Flows from Financing Activities were $481 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 reaquisition 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 and paid $95 million in common stock dividends to Parent.
Net Cash Flows from Financing Activities were $222 million in 2008. OPCo issued $244 million of Pollution Control Bonds and $250 million of Senior Unsecured Notes. These increases were partially offset by the retirement of $250 million of Pollution Control Bonds, $37 million of Senior Unsecured Notes and $18 million of Notes Payable – Nonaffiliated.
CONTRACTUAL OBLIGATION INFORMATION
OPCo’s contractual cash obligations include amounts reported on OPCo’s Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes OPCo’s contractual cash obligations at December 31, 2010:
| | Payments Due by Period |
| | |
| | | | | Less Than | | | | | | After | | |
| | Contractual Cash Obligations | | 1 year | | 2-3 years | | 4-5 years | | 5 years | | Total |
| | | | | |
| | | | | | | | | | | | | | | | | |
| | Interest on Fixed Rate Portion of Long-term Debt (a) | | $ | 140.4 | | $ | 274.0 | | $ | 198.0 | | $ | 814.2 | | $ | 1,426.6 |
| | Fixed Rate Portion of Long-term Debt (b) | | | - | | | 500.0 | | | 629.6 | | | 1,440.0 | | | 2,569.6 |
| | Variable Rate Portion of Long-term Debt (c) | | | 165.0 | | | - | | | - | | | - | | | 165.0 |
| | Capital Lease Obligations (d) | | | 11.7 | | | 18.3 | | | 11.4 | | | 22.0 | | | 63.4 |
| | Noncancelable Operating Leases (d) | | | 20.7 | | | 38.4 | | | 36.1 | | | 71.4 | | | 166.6 |
| | Fuel Purchase Contracts (e) | | | 887.8 | | | 1,546.7 | | | 1,184.4 | | | 2,551.6 | | | 6,170.5 |
| | Energy and Capacity Purchase Contracts (f) | | | 6.5 | | | 8.8 | | | 3.4 | | | 21.5 | | | 40.2 |
| | Construction Contracts for Capital Assets (g) | | | 43.3 | | | 62.4 | | | 65.5 | | | 109.0 | | | 280.2 |
| | Total | | $ | 1,275.4 | | $ | 2,448.6 | | $ | 2,128.4 | | $ | 5,029.7 | | $ | 10,882.1 |
| (a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2010 and do not reflect anticipated future refinancings, early redemptions or debt issuances. |
| (b) | See “Long-term Debt” section of Note 14. Represents principal only excluding interest. |
| (c) | See “Long-term Debt” section of Note 14. Represents principal only excluding interest. Variable rate debt had interest rates that ranged between 0.30% and 0.48% at December 31, 2010. |
| (d) | See Note 13. |
| (e) | Represents contractual obligations to purchase coal and other consumables as fuel for electric generation along with related transportation of the fuel. |
| (f) | Represents contractual obligations for energy and capacity purchase contracts. |
| (g) | Represents only capital assets for which OPCo has signed contracts. Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs. |
OPCo’s $21 million liability related to uncertainty in Income Taxes is not included above because management cannot reasonably estimate the cash flows by period.
OPCo’s pension funding requirements are not included in the above table. As of December 31, 2010, management expects to make contributions to the pension plans totaling $12.6 million in 2011. Estimated contributions of $17.9 million in 2012 and $18 million in 2013 may vary significantly based on market returns, changes in actuarial assumptions and other factors. Based upon the benefit obligation and fair value of assets available to pay pension benefits, OPCo’s pension plan obligation was 82.3% funded as of December 31, 2010.
In addition to the amounts disclosed in the contractual cash obligations table above, OPCo makes additional commitments in the normal course of business. OPCo’s commitments outstanding at December 31, 2010 under these agreements are summarized in the table below:
| | Amount of Commitment Expiration Per Period |
| | |
| | | | Less Than | | | | | | After | | |
| | Other Commercial Commitments | | 1 year | | 2-3 years | | 4-5 years | | 5 years | | Total |
| | | | (in millions) |
| | Standby Letters of Credit (a) | | $ | 166.9 | | $ | - | | $ | - | | $ | - | | $ | 166.9 |
| (a) | OPCo enters into standby letters of credit (LOCs) with third parties. These LOCs cover items such as insurance programs, security deposits, debt service reserves and variable rate Pollution Control Bonds. All of these LOCs were issued in OPCo’s ordinary course of business. There is no collateral held in relation to any guarantees in excess of OPCo's ownership percentages. In the event any LOC is drawn, there is no recourse to third parties. The maximum future payments of these LOCs are $166.9 million maturing in April 2011. See “Letters of Credit” section of Note 6. |
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” beginning on page 405 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 Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 for a discussion of the adoption and impact of new accounting pronouncements.
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 405 for a discussion of risk management activities.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Ohio Power Company:
We have audited the accompanying consolidated balance sheets of Ohio Power Company Consolidated (the "Company") as of December 31, 2010 and 2009, and the related consolidated statements of income, changes in equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Ohio Power Company Consolidated as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Columbus, Ohio
February 25, 2011
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Ohio Power Company Consolidated (OPCo) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. OPCo’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of OPCo’s internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on management’s assessment, OPCo’s internal control over financial reporting was effective as of December 31, 2010.
This annual report does not include an attestation report of OPCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit OPCo to provide only management’s report in this annual report.
| OHIO POWER COMPANY CONSOLIDATED | |
| CONSOLIDATED STATEMENTS OF INCOME | |
| For the Years Ended December 31, 2010, 2009 and 2008 | |
| (in thousands) | |
| | |
| | | 2010 | | | 2009 | | | 2008 | |
| REVENUES | | | | | | | | | |
| Electric Generation, Transmission and Distribution | | $ | 2,159,206 | | | $ | 1,941,257 | | | $ | 2,116,797 | |
| Sales to AEP Affiliates | | | 1,025,923 | | | | 1,034,290 | | | | 940,468 | |
| Other Revenues - Affiliated | | | 21,069 | | | | 23,457 | | | | 20,732 | |
| Other Revenues - Nonaffiliated | | | 17,509 | | | | 12,570 | | | | 18,937 | |
| TOTAL REVENUES | | | 3,223,707 | | | | 3,011,574 | | | | 3,096,934 | |
| | | | | | | | | | | | | |
| EXPENSES | | | | | | | | | | | | |
| Fuel and Other Consumables Used for Electric Generation | | | 1,088,588 | | | | 988,520 | | | | 1,190,939 | |
| Purchased Electricity for Resale | | | 180,721 | | | | 178,123 | | | | 175,429 | |
| Purchased Electricity from AEP Affiliates | | | 93,971 | | | | 74,598 | | | | 140,686 | |
| Other Operation | | | 446,264 | | | | 386,323 | | | | 414,945 | |
| Maintenance | | | 238,356 | | | | 224,439 | | | | 213,431 | |
| Depreciation and Amortization | | | 361,728 | | | | 352,068 | | | | 273,720 | |
| Taxes Other Than Income Taxes | | | 206,277 | | | | 194,310 | | | | 192,734 | |
| TOTAL EXPENSES | | | 2,615,905 | | | | 2,398,381 | | | | 2,601,884 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 607,802 | | | | 613,193 | | | | 495,050 | |
| | | | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | | | |
| Interest Income | | | 1,648 | | | | 1,436 | | | | 6,515 | |
| Carrying Costs Income | | | 23,630 | | | | 10,698 | | | | 16,309 | |
| Allowance for Equity Funds Used During Construction | | | 3,877 | | | | 2,712 | | | | 3,073 | |
| Interest Expense | | | (156,107 | ) | | | (152,950 | ) | | | (173,870 | ) |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAX EXPENSE | | | 480,850 | | | | 475,089 | | | | 347,077 | |
| | | | | | | | | | | | | |
| Income Tax Expense | | | 169,457 | | | | 166,474 | | | | 114,622 | |
| | | | | | | | | | | | | |
| NET INCOME | | | 311,393 | | | | 308,615 | | | | 232,455 | |
| | | | | | | | | | | | | |
| Less: Net Income Attributable to Noncontrolling Interest | | | - | | | | 2,042 | | | | 1,332 | |
| | | | | | | | | | | | | |
NET INCOME ATTRIBUTABLE TO OPCo SHAREHOLDERS | | | 311,393 | | | | 306,573 | | | | 231,123 | |
| | | | | | | | | | | | | |
| Less: Preferred Stock Dividend Requirements | | | 732 | | | | 732 | | | | 732 | |
| | | | | | | | | | | | | |
| EARNINGS ATTRIBUTABLE TO OPCo COMMON SHAREHOLDER | | $ | 310,661 | | | $ | 305,841 | | | $ | 230,391 | |
| | | | | | | | | | | | | |
| The common stock of OPCo is wholly-owned by AEP. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
| OHIO POWER COMPANY CONSOLIDATED |
| CONSOLIDATED STATEMENTS OF CHANGES IN |
| EQUITY AND COMPREHENSIVE INCOME (LOSS) |
| For the Years Ended December 31, 2010, 2009 and 2008 |
| (in thousands) |
| | | | | | | | | | | | | | | | | | | |
| | | OPCo Common Shareholder | | | | | | |
| | | | | | | | | | | | Accumulated | | | | | |
| | | | | | | | | | | | Other | | | | | |
| | | Common | | Paid-in | | Retained | | Comprehensive | | Noncontrolling | | |
| | | Stock | | Capital | | Earnings | | Income (Loss) | | Interest | | Total |
| | | | | | | | | | | | | | | | | | | |
| TOTAL EQUITY – DECEMBER 31, 2007 | | $ | 321,201 | | $ | 536,640 | | $ | 1,469,717 | | $ | (36,541) | | $ | 15,923 | | $ | 2,306,940 |
| | | | | | | | | | | | | | | | | | | |
| Adoption of Guidance for Split-Dollar Life Insurance | | | | | | | | | | | | | | | | | | |
| | Accounting, Net of Tax of $1,004 | | | | | | | | | (1,864) | | | | | | | | | (1,864) |
| Adoption of Guidance for Fair Value Accounting, | | | | | | | | | | | | | | | | | | |
| | Net of Tax of $152 | | | | | | | | | (282) | | | | | | | | | (282) |
| Common Stock Dividends – Nonaffilated | | | | | | | | | | | | | | | (1,332) | | | (1,332) |
| Preferred Stock Dividends | | | | | | | | | (732) | | | | | | | | | (732) |
| Other Changes in Equity | | | | | | | | | | | | | | | 876 | | | 876 |
| SUBTOTAL – EQUITY | | | | | | | | | | | | | | | | | | 2,303,606 |
| | | | | | | | | | | | | | | | | | | | |
| COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | |
| Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | | | | |
| | | Cash Flow Hedges, Net of Tax of $1,343 | | | | | | | | | | | | 2,493 | | | | | | 2,493 |
| | | Amortization of Pension and OPEB Deferred Costs, | | | | | | | | | | | | | | | | | | |
| | | | Net of Tax of $1,515 | | | | | | | | | | | | 2,813 | | | | | | 2,813 |
| | | Pension and OPEB Funded Status, | | | | | | | | | | | | | | | | | | |
| | | | Net of Tax of $55,259 | | | | | | | | | | | | (102,623) | | | | | | (102,623) |
| NET INCOME | | | | | | | | | 231,123 | | | | | | 1,332 | | | 232,455 |
| TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | 135,138 |
| | | | | | | | | | | | | | | | | | | | | | |
| 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 | | | | | | | | | (95,000) | | | | | | | | | (95,000) |
| Common Stock Dividends – Nonaffiliated | | | | | | | | | | | | | | | (2,042) | | | (2,042) |
| Preferred Stock Dividends | | | | | | | | | (732) | | | | | | | | | (732) |
| Purchase of JMG | | | | | | 36,509 | | | | | | | | | (17,910) | | | 18,599 |
| Other Changes in Equity | | | | | | | | | | | | | | | 1,111 | | | 1,111 |
| SUBTOTAL – EQUITY | | | | | | | | | | | | | | | | | | 2,910,680 |
| | | | | | | | | | | | | | | | | | | |
| COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | |
| Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | |
| | | Cash Flow Hedges, Net of Tax of $4,392 | | | | | | | | | | | | 8,156 | | | | | | 8,156 |
| | | Amortization of Pension and OPEB Deferred Costs, | | | | | | | | | | | | | | | | | | |
| | | | Net of Tax of $3,421 | | | | | | | | | | | | 6,353 | | | | | | 6,353 |
| | | Pension and OPEB Funded Status, Net of Tax of $480 | | | | | | | | | | | | 891 | | | | | | 891 |
| NET INCOME | | | | | | | | | 306,573 | | | | | | 2,042 | | | 308,615 |
| TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | 324,015 |
| | | | | | | | | | | | | | | | | | | |
| TOTAL EQUITY – DECEMBER 31, 2009 | | | 321,201 | | | 1,123,149 | | | 1,908,803 | | | (118,458) | | | - | | | 3,234,695 |
| | | | | | | | | | | | | | | | | | | |
| Common Stock Dividends | | | | | | | | | (366,575) | | | | | | | | | (366,575) |
| Preferred Stock Dividends | | | | | | | | | (732) | | | | | | | | | (732) |
| Gain on Reacquired Preferred Stock | | | | | | 4 | | | | | | | | | | | | 4 |
| SUBTOTAL – EQUITY | | | | | | | | | | | | | | | | | | 2,867,392 |
| | | | | | | | | | | | | | | | | | | |
| COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | |
| Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | | | | |
| | | Cash Flow Hedges, Net of Tax of $659 | | | | | | | | | | | | (1,223) | | | | | | (1,223) |
| | | Amortization of Pension and OPEB Deferred Costs, | | | | | | | | | | | | | | | | | | |
| | | | Net of Tax of $3,795 | | | | | | | | | | | | 7,047 | | | | | | 7,047 |
| | | Pension and OPEB Funded Status, Net of Tax of $8,715 | | | | | | | | | | | | (16,185) | | | | | | (16,185) |
| NET INCOME | | | | | | | | | 311,393 | | | | | | | | | 311,393 |
| TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | 301,032 |
| | | | | | | | | | | | | | | | | | | |
| TOTAL EQUITY – DECEMBER 31, 2010 | | $ | 321,201 | | $ | 1,123,153 | | $ | 1,852,889 | | $ | (128,819) | | $ | - | | $ | 3,168,424 |
| |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. |
| OHIO POWER COMPANY CONSOLIDATED | |
| CONSOLIDATED BALANCE SHEETS | |
| ASSETS | |
| December 31, 2010 and 2009 | |
| (in thousands) | |
| | |
| | | 2010 | | | 2009 | |
| CURRENT ASSETS | | | | | | |
| Cash and Cash Equivalents | | $ | 440 | | | $ | 1,984 | |
| Advances to Affiliates | | | 100,500 | | | | 438,352 | |
| Accounts Receivable: | | | | | | | | |
| Customers | | | 86,186 | | | | 60,711 | |
| Affiliated Companies | | | 198,845 | | | | 200,579 | |
| Accrued Unbilled Revenues | | | 27,928 | | | | 15,021 | |
| Miscellaneous | | | 2,368 | | | | 2,701 | |
| Allowance for Uncollectible Accounts | | | (2,184 | ) | | | (2,665 | ) |
| Total Accounts Receivable | | | 313,143 | | | | 276,347 | |
| Fuel | | | 257,289 | | | | 336,866 | |
| Materials and Supplies | | | 134,181 | | | | 115,486 | |
| Risk Management Assets | | | 30,773 | | | | 50,048 | |
| Accrued Tax Benefits | | | 69,021 | | | | 143,473 | |
| Prepayments and Other Current Assets | | | 33,998 | | | | 26,301 | |
| TOTAL CURRENT ASSETS | | | 939,345 | | | | 1,388,857 | |
| | | | | | | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
| Electric: | | | | | | | | |
| Generation | | | 6,890,110 | | | | 6,731,469 | |
| Transmission | | | 1,234,677 | | | | 1,166,557 | |
| Distribution | | | 1,626,390 | | | | 1,567,871 | |
| Other Property, Plant and Equipment | | | 359,254 | | | | 348,718 | |
| Construction Work in Progress | | | 153,110 | | | | 198,843 | |
| Total Property, Plant and Equipment | | | 10,263,541 | | | | 10,013,458 | |
| Accumulated Depreciation and Amortization | | | 3,606,777 | | | | 3,318,896 | |
| TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 6,656,764 | | | | 6,694,562 | |
| | | | | | | | | |
| OTHER NONCURRENT ASSETS | | | | | | | | |
| Regulatory Assets | | | 934,011 | | | | 742,905 | |
| Long-term Risk Management Assets | | | 28,012 | | | | 28,003 | |
| Deferred Charges and Other Noncurrent Assets | | | 189,195 | | | | 184,812 | |
| TOTAL OTHER NONCURRENT ASSETS | | | 1,151,218 | | | | 955,720 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 8,747,327 | | | $ | 9,039,139 | |
| | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
| OHIO POWER COMPANY CONSOLIDATED | |
| CONSOLIDATED BALANCE SHEETS | |
| LIABILITIES AND EQUITY | |
| December 31, 2010 and 2009 | |
| | |
| | | 2010 | | | 2009 | |
| | | (in thousands) | |
| CURRENT LIABILITIES | | | | | | |
| Accounts Payable: | | | | | | |
| General | | $ | 170,240 | | | $ | 182,848 | |
| Affiliated Companies | | | 136,215 | | | | 92,766 | |
| Long-term Debt Due Within One Year – Nonaffiliated | | | 165,000 | | | | 679,450 | |
| Risk Management Liabilities | | | 22,166 | | | | 24,391 | |
| Customer Deposits | | | 28,228 | | | | 22,409 | |
| Accrued Taxes | | | 229,253 | | | | 203,335 | |
| Accrued Interest | | | 46,184 | | | | 46,431 | |
| Other Current Liabilities | | | 98,687 | | | | 104,889 | |
| TOTAL CURRENT LIABILITIES | | | 895,973 | | | | 1,356,519 | |
| | | | | | | | | |
| NONCURRENT LIABILITIES | | | | | | | | |
| Long-term Debt – Nonaffiliated | | | 2,364,522 | | | | 2,363,055 | |
| Long-term Debt – Affiliated | | | 200,000 | | | | 200,000 | |
| Long-term Risk Management Liabilities | | | 8,403 | | | | 12,510 | |
| Deferred Income Taxes | | | 1,531,639 | | | | 1,302,939 | |
| Regulatory Liabilities and Deferred Investment Tax Credits | | | 126,403 | | | | 128,187 | |
| Employee Benefits and Pension Obligations | | | 246,517 | | | | 269,485 | |
| Deferred Credits and Other Noncurrent Liabilities | | | 188,830 | | | | 155,122 | |
| TOTAL NONCURRENT LIABILITIES | | | 4,666,314 | | | | 4,431,298 | |
| | | | | | | | | |
| TOTAL LIABILITIES | | | 5,562,287 | | | | 5,787,817 | |
| | | | | | | | | |
| Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 16,616 | | | | 16,627 | |
| | | | | | | | | |
| Rate Matters (Note 4) | | | | | | | | |
| Commitments and Contingencies (Note 6) | | | | | | | | |
| | | | | | | | | |
| 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 | | | | 1,123,149 | |
| Retained Earnings | | | 1,852,889 | | | | 1,908,803 | |
| Accumulated Other Comprehensive Income (Loss) | | | (128,819 | ) | | | (118,458 | ) |
| TOTAL COMMON SHAREHOLDER’S EQUITY | | | 3,168,424 | | | | 3,234,695 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | | $ | 8,747,327 | | | $ | 9,039,139 | |
| | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
| OHIO POWER COMPANY CONSOLIDATED | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| For the Years Ended December 31, 2010, 2009 and 2008 | |
| (in thousands) | |
| | | | | | | | | | |
| | | 2010 | | | 2009 | | | 2008 | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net Income | | $ | 311,393 | | | $ | 308,615 | | | $ | 232,455 | |
| Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | | | | | |
| Depreciation and Amortization | | | 361,728 | | | | 352,068 | | | | 273,720 | |
| Deferred Income Taxes | | | 218,246 | | | | 382,794 | | | | 42,717 | |
| Carrying Costs Income | | | (23,630 | ) | | | (10,698 | ) | | | (16,309 | ) |
| Allowance for Equity Funds Used During Construction | | | (3,877 | ) | | | (2,712 | ) | | | (3,073 | ) |
| Mark-to-Market of Risk Management Contracts | | | 13,444 | | | | (5,486 | ) | | | (13,839 | ) |
| Pension Contributions to Qualified Plan Trust | | | (51,641 | ) | | | - | | | | - | |
| Property Taxes | | | (6,861 | ) | | | (7,109 | ) | | | (5,507 | ) |
| Fuel Over/Under-Recovery, Net | | | (153,643 | ) | | | (297,570 | ) | | | - | |
| Change in Other Noncurrent Assets | | | 3,200 | | | | 4,913 | | | | (48,653 | ) |
| Change in Other Noncurrent Liabilities | | | (6,418 | ) | | | 35,130 | | | | (10,445 | ) |
| Changes in Certain Components of Working Capital: | | | | | | | | | | | | |
| Accounts Receivable, Net | | | (38,066 | ) | | | (29,927 | ) | | | 5,104 | |
| Fuel, Materials and Supplies | | | 64,801 | | | | (155,557 | ) | | | (89,058 | ) |
| Accounts Payable | | | 43,060 | | | | (121,117 | ) | | | 126,716 | |
| Customer Deposits | | | 5,819 | | | | (1,924 | ) | | | (6,280 | ) |
| Accrued Taxes, Net | | | 87,476 | | | | (119,428 | ) | | | (11,210 | ) |
| Other Current Assets | | | (1,310 | ) | | | 2,877 | | | | (10,730 | ) |
| Other Current Liabilities | | | (1,914 | ) | | | (13,835 | ) | | | 20,269 | |
| Net Cash Flows from Operating Activities | | | 821,807 | | | | 321,034 | | | | 485,877 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction Expenditures | | | (276,736 | ) | | | (417,601 | ) | | | (706,315 | ) |
| Change in Advances to Affiliates, Net | | | 337,852 | | | | (438,352 | ) | | | - | |
| Acquisitions of Assets | | | (5,059 | ) | | | (1,197 | ) | | | (2,033 | ) |
| Proceeds from Sales of Assets | | | 17,211 | | | | 38,640 | | | | 8,293 | |
| Other Investing Activities | | | (156 | ) | | | 5,529 | | | | (1,734 | ) |
| Net Cash Flows from (Used for) Investing Activities | | | 73,112 | | | | (812,981 | ) | | | (701,789 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Capital Contribution from Parent | | | - | | | | 550,000 | | | | - | |
| Issuance of Long-term Debt – Nonaffiliated | | | 202,380 | | | | 493,775 | | | | 491,204 | |
| Change in Short-term Debt, Net – Nonaffiliated | | | - | | | | - | | | | (701 | ) |
| Change in Advances from Affiliates, Net | | | - | | | | (133,887 | ) | | | 32,339 | |
| Retirement of Long-term Debt – Nonaffiliated | | | (718,580 | ) | | | (295,500 | ) | | | (305,188 | ) |
| Retirement of Cumulative Preferred Stock | | | (7 | ) | | | (1 | ) | | | - | |
| Principal Payments for Capital Lease Obligations | | | (7,447 | ) | | | (4,271 | ) | | | (5,736 | ) |
| Dividends Paid on Common Stock – Nonaffiliated | | | - | | | | (2,042 | ) | | | (1,332 | ) |
| Dividends Paid on Common Stock – Affiliated | | | (366,575 | ) | | | (95,000 | ) | | | - | |
| Dividends Paid on Cumulative Preferred Stock | | | (732 | ) | | | (732 | ) | | | (732 | ) |
| Acquisition of JMG Noncontrolling Interest | | | - | | | | (28,221 | ) | | | - | |
| Other Financing Activities | | | (5,502 | ) | | | (2,869 | ) | | | 12,071 | |
| Net Cash Flows from (Used for) Financing Activities | | | (896,463 | ) | | | 481,252 | | | | 221,925 | |
| | | | | | | | | | | | | |
| Net Increase (Decrease) in Cash and Cash Equivalents | | | (1,544 | ) | | | (10,695 | ) | | | 6,013 | |
| Cash and Cash Equivalents at Beginning of Period | | | 1,984 | | | | 12,679 | | | | 6,666 | |
| Cash and Cash Equivalents at End of Period | | $ | 440 | | | $ | 1,984 | | | $ | 12,679 | |
| | | | | | | | | | | | | |
| SUPPLEMENTARY INFORMATION | | | | | | | | | | | | |
| Cash Paid for Interest, Net of Capitalized Amounts | | $ | 154,744 | | | $ | 147,573 | | | $ | 144,790 | |
| Net Cash Paid (Received) for Income Taxes | | | (115,073 | ) | | | (62,704 | ) | | | 100,430 | |
| Noncash Acquisitions Under Capital Leases | | | 23,736 | | | | 2,383 | | | | 3,910 | |
| Noncash Acquisitions of Coal Land Rights | | | - | | | | - | | | | 41,600 | |
| Construction Expenditures Included in Accounts Payable at December 31, | | | 17,710 | | | | 29,929 | | | | 33,177 | |
| SIA Refund Included in Accounts Payable at December 31, | | | - | | | | - | | | | 62,045 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
OHIO POWER COMPANY CONSOLIDATED
INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The notes to OPCo’s financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to OPCo. The footnotes begin on page 246.
| | Footnote Reference |
| | |
| Organization and Summary of Significant Accounting Policies | Note 1 |
| New Accounting Pronouncements and Extraordinary Item | Note 2 |
| Rate Matters | Note 4 |
| Effects of Regulation | Note 5 |
| Commitments, Guarantees and Contingencies | Note 6 |
| Benefit Plans | Note 8 |
| Business Segments | Note 9 |
| Derivatives and Hedging | Note 10 |
| Fair Value Measurements | Note 11 |
| Income Taxes | Note 12 |
| Leases | Note 13 |
| Financing Activities | Note 14 |
| Related Party Transactions | Note 15 |
| Property, Plant and Equipment | Note 16 |
| Cost Reduction Initiatives | Note 17 |
| Unaudited Quarterly Financial Information | Note 18 |
PUBLIC SERVICE COMPANY OF OKLAHOMA
| PUBLIC SERVICE COMPANY OF OKLAHOMA |
| SELECTED FINANCIAL DATA |
| (in thousands) |
| |
| | | | | 2010 | | 2009 | | 2008 | | 2007 | | 2006 |
| STATEMENTS OF OPERATIONS DATA | | | | | | | | | | | | | | | |
| Total Revenues | | $ | 1,273,662 | | $ | 1,124,750 | | $ | 1,655,945 | (a) | $ | 1,395,550 | | $ | 1,441,784 |
| | | | | | | | | | | | | | | | | | |
| Operating Income (Loss) | | $ | 181,992 | | $ | 170,308 | | $ | 160,463 | (a)(b) | $ | (4,835) | (c) | $ | 90,993 |
| | | | | | | | | | | | | | | | | | |
| Net Income (Loss) | | $ | 72,787 | | $ | 75,602 | | $ | 78,484 | (a)(b) | $ | (24,124) | (c) | $ | 36,860 |
| | | | | | | | | | | | | | | | | | |
| BALANCE SHEETS DATA | | | | | | | | | | | | | | | |
| Total Property, Plant and Equipment | | $ | 3,975,329 | | $ | 3,809,558 | | $ | 3,692,011 | | $ | 3,459,181 | | $ | 3,186,294 |
| Accumulated Depreciation and Amortization | | | 1,255,064 | | | 1,220,177 | | | 1,192,130 | | | 1,182,171 | | | 1,187,107 |
| Total Property, Plant and Equipment – Net | | $ | 2,720,265 | | $ | 2,589,381 | | $ | 2,499,881 | | $ | 2,277,010 | | $ | 1,999,187 |
| | | | | | | | | | | | | | | | | | |
| Total Assets | | $ | 3,284,071 | | $ | 3,169,207 | | $ | 3,100,798 | | $ | 2,843,871 | | $ | 2,565,579 |
| | | | | | | | | | | | | | | | | | |
| Total Common Shareholder's Equity | | $ | 842,472 | | $ | 811,742 | | $ | 748,246 | | $ | 640,898 | | $ | 585,438 |
| | | | | | | | | | | | | | | | | | |
| Cumulative Preferred Stock Not Subject to | | | | | | | | | | | | | | | |
| | Mandatory Redemption | | $ | 4,882 | | $ | 5,258 | | $ | 5,262 | | $ | 5,262 | | $ | 5,262 |
| | | | | | | | | | | | | | | | | | |
| Long-term Debt (d) | | $ | 971,186 | | $ | 968,121 | | $ | 884,859 | | $ | 918,316 | | $ | 669,998 |
| | | | | | | | | | | | | | | | | | |
| Obligations Under Capital Leases (d) | | $ | 18,389 | (e) | $ | 5,470 | | $ | 3,478 | | $ | 4,028 | | $ | 4,816 |
| (a) | Includes the net favorable effect of the recognition of off-system sales margins as ordered by the FERC in November 2008. See “Allocation of Off-system Sales Margins” section of Note 4. |
| (b) | Includes the favorable effect of the 2008 deferral of Oklahoma ice storm expenses incurred in 2007. |
| (c) | Includes expenses incurred from ice storms in January and December 2007. |
| (d) | Includes portion due within one year. |
| (e) | Obligations Under Capital Leases increased primarily due to capital leases under new master lease agreements for property that was previously leased under operating leases. |
PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
EXECUTIVE OVERVIEW
Company Overview
As a public utility, PSO engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to approximately 532,000 retail customers in its service territory in eastern and southwestern Oklahoma. PSO sells electric power at wholesale to other utilities, municipalities and electric cooperatives.
PSO, as a member of the CSW Operating Agreement, is compensated for energy delivered to the other member based upon the delivering member’s incremental cost plus a portion of the savings realized by the purchasing member that avoids the use of more costly alternatives. PSO and SWEPCo share the revenues and costs of sales to neighboring utilities and power marketers made by AEPSC on their behalf based upon the relative magnitude of the energy each company provides to make such sales. PSO shares off-system sales margins, if positive on an annual basis, with its customers.
Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and gas risk management activities based upon the location of such activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP generally accruing to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among the AEP East companies, PSO and SWEPCo in proportion to the marketing realization directly assigned to each zone for the current month plus the preceding eleven months.
AEPSC conducts power, gas, coal and emission allowance risk management activities on PSO’s behalf. PSO shares in the revenues and expenses associated with these risk management activities, as described in the preceding paragraph, with the AEP East companies and SWEPCo. Power and gas risk management activities are allocated based on the CSW Operating Agreement and the SIA. PSO shares in coal and emission allowance risk management activities based on its proportion of fossil fuels burned by the AEP System. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas, coal and emission allowances. The electricity, gas, coal and emission allowance contracts include phys ical transactions, OTC options and financially-settled swaps and exchange-traded futures and options. AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts.
PSO is jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East companies, PSO and SWEPCo related to purchase power and sale activity pursuant to the SIA.
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 included a $24 million increase in depreciation and an 11.5% return on common equity. In January 2011, the OCC approved a settlement agreement which did not change annual revenue or depreciation rates, but transferred $30 million into base rates that was previously being recovered through a capital investment rider. The order provided a 10.15% return on common equity and new rates were effective in February 2011. See “2010 Oklahoma Base Rate Case” section of Note 4.
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. 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 405 for additional discussion of relevant factors.
RESULTS OF OPERATIONS
KWH Sales/Degree Days
| Summary of KWH Energy Sales |
| | | | | | | | | | |
| | | Years Ended December 31, |
| | 2010 | | 2009 | | 2008 |
| | | (in millions of KWH) |
| Retail: | | | | | | | | |
| | Residential | | 6,595 | | | 6,004 | | | 5,997 |
| | Commercial | | 5,136 | | | 4,974 | | | 4,890 |
| | Industrial | | 4,921 | | | 4,742 | | | 5,551 |
| | Miscellaneous | | 1,265 | | | 1,236 | | | 1,315 |
| Total Retail | | 17,917 | | | 16,956 | | | 17,753 |
| | | | | | | | | |
| Wholesale | | 1,190 | | | 982 | | | 949 |
| | | | | | | | | |
| Total KWHs | | 19,107 | | | 17,938 | | | 18,702 |
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 |
| | | | | | | | | | | |
| | | | Years Ended December 31, |
| | | | 2010 | | 2009 | | 2008 |
| | | | (in degree days) |
| | | | | | | | | | | |
| | Actual - Heating (a) | | 1,993 | | | 1,840 | | | 1,864 |
| | Normal - Heating (b) | | 1,784 | | | 1,789 | | | 1,809 |
| | | | | | | | | | | |
| | Actual - Cooling (c) | | 2,380 | | | 1,861 | | | 2,003 |
| | Normal - Cooling (b) | | 2,095 | | | 2,126 | | | 2,130 |
| | | | | | | | | | | |
| | (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. |
| 2010 Compared to 2009 | |
| | | | |
| Reconciliation of Year Ended December 31, 2009 to Year Ended December 31, 2010 | |
| Net Income | |
| (in millions) | |
| | | | |
| Year Ended December 31, 2009 | | $ | 76 | |
| | | | | |
| 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 | | | (45 | ) |
| Depreciation and Amortization | | | 5 | |
| Taxes Other Than Income Taxes | | | (1 | ) |
| Other Income | | | (4 | ) |
| Interest Expense | | | (4 | ) |
| Total Expenses and Other | | | (49 | ) |
| | | | | |
| Income Tax Expense | | | (6 | ) |
| | | | | |
| Year Ended December 31, 2010 | | $ | 73 | |
| (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 $37 million increase primarily due to rate increases. |
| | · | A $27 million increase in weather-related usage primarily due to a 28% increase in cooling degree days and an 8% increase in heating degree days. |
| | These increases were partially offset by: |
| | · | A $10 million decrease primarily due to lower wholesale municipal customer revenues and increased capacity and fuel costs. |
Total Expenses and Other and Income Tax Expense changed between years as follows:
| · | Other Operation and Maintenance expenses increased $45 million primarily due to the following: |
| | · | A $24 million increase primarily due to expenses related to cost reduction initiatives. In 2010, management conducted cost reduction initiatives to reduce both labor and non-labor expenses. |
| | · | A $9 million increase in demand side management programs. |
| | · | A $7 million increase in plant maintenance expense resulting primarily from the 2009 deferral of generation maintenance expenses as a result of PSO’s 2008 base rate case. |
| | · | A $5 million increase in employee-related expenses. |
| · | Depreciation and Amortization expenses decreased $5 million primarily due to a decrease in amortization of regulatory assets related to Generation Cost Recovery (GCR) and the Lawton Settlement which were fully recovered in August 2009 and August 2010, respectively. The decrease was partially offset by an increase in depreciation on higher levels of depreciable plant and by the amortization of storm-related regulatory assets. |
| · | Other Income decreased $4 million primarily due to the following: |
| | · | A $2 million decrease in interest income primarily due to the Lawton Settlement regulatory asset. |
| | · | A $1 million decrease in carrying charges for GCR and storm-related regulatory assets. |
| · | Interest Expense increased $4 million primarily due to increased long-term debt outstanding. |
| · | Income Tax Expense increased $6 million due to the recording of state income tax adjustments and to an increase in pretax book income. |
| 2009 Compared to 2008 | |
| | | | |
| Reconciliation of Year Ended December 31, 2008 to Year Ended December 31, 2009 | |
| Net Income | |
| (in millions) | |
| | | | |
| Year Ended December 31, 2008 | | $ | 78 | |
| | | | | |
| Changes in Gross Margin: | | | | |
| Retail Margins (a) | | | 75 | |
| Off-system Sales | | | (3 | ) |
| Transmission Revenues | | | 2 | |
| Other Revenues | | | (11 | ) |
| Total Change in Gross Margin | | | 63 | |
| | | | | |
| Total Expenses and Other: | | | | |
| Other Operation and Maintenance | | | 29 | |
| Deferral of Ice Storm Costs | | | (74 | ) |
| Depreciation and Amortization | | | (5 | ) |
| Taxes Other Than Income Taxes | | | (3 | ) |
| Other Income | | | (23 | ) |
| Carrying Costs Income | | | (5 | ) |
| Interest Expense | | | 18 | |
| Total Expenses and Other | | | (63 | ) |
| | | | | |
| Income Tax Expense | | | (2 | ) |
| | | | | |
| Year Ended December 31, 2009 | | $ | 76 | |
| (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 $75 million primarily due to the following: |
| | · | An $86 million increase primarily resulting from base rate increases during the year, including revenue increases from rate riders of $22 million. This increase in rider revenue was offset by a corresponding $14 million increase in Other Operation and Maintenance expenses and a $4 million increase in Depreciation and Amortization expenses discussed below. |
| | This increase was partially offset by: |
| | · | A $14 million decrease due to the net favorable effect of the recognition of off-system sales margins as ordered by the FERC in November 2008. |
| · | Other Revenues decreased $11 million primarily due to the recognition of the sale of SO2 allowances in 2008, partially offset by a corresponding $9 million decrease in Other Operation and Maintenance expenses discussed below. |
Total Expenses and Other and Income Tax Expense changed between years as follows:
| · | Other Operation and Maintenance expenses decreased $29 million primarily due to the following: |
| | · | The write-off in 2008 of $10 million of unrecoverable pre-construction costs related to the cancelled Red Rock Generating Facility. |
| | · | An $8 million decrease in plant maintenance expense primarily due to the deferral of generation maintenance expenses as a result of PSO’s 2008 base rate case. |
| | · | A $5 million decrease in contributions. |
| | · | A $4 million decrease primarily resulting from the reduced sale of receivable expense due to decreased revenues. |
| | · | A $3 million decrease in expense related to maintenance of overhead transmission lines and miscellaneous transmission maintenance expenses. |
| | These decreases were partially offset by: |
| | · | A $5 million net increase due to increased amortization of regulatory assets and liabilities related to the 2007 ice storm, demand side management and distribution vegetation management, offset by a corresponding increase in rider revenue discussed above. |
| · | Deferral of Ice Storm Costs in 2008 of $74 million results from an OCC order approving recovery of ice storm costs incurred in January and December 2007. |
| · | Depreciation and Amortization expenses increased $5 million primarily due to a $4 million increase in amortization of regulatory assets, the largest of which was related to the GCR regulatory asset. This increase was offset by a corresponding increase in rider revenue discussed above. |
| · | Other Income decreased $23 million primarily due to interest income in 2008 from the AEP East companies for the refund of off-system sales margins in accordance with the FERC’s order related to the SIA. |
| · | Carrying Costs Income decreased $5 million due to the declining balance of unrecovered GCR regulatory assets being collected from customers, which were fully recovered in August 2009. |
| · | Interest Expense decreased $18 million primarily due to interest expense to customers in 2008 for off-system sales margins in accordance with the FERC’s order related to the SIA. |
| · | Income Tax Expense increased $2 million primarily due to an increase in state income tax expense, partially offset by a decrease in pretax book income. |
FINANCIAL CONDITION
LIQUIDITY
PSO participates in the Utility Money Pool, which provides access to AEP’s liquidity. PSO 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 405 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 2010, 2009 and 2008 were as follows:
| | | Years Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (in thousands) | |
| Cash and Cash Equivalents at Beginning of Period | | $ | 796 | | | $ | 1,345 | | | $ | 1,370 | |
| Cash Flows from (Used for): | | | | | | | | | | | | |
| Operating Activities | | | 93,946 | | | | 239,653 | | | | 167,956 | |
| Investing Activities | | | (132,569 | ) | | | (237,975 | ) | | | (233,464 | ) |
| Financing Activities | | | 38,297 | | | | (2,227 | ) | | | 65,483 | |
| Net Decrease in Cash and Cash Equivalents | | | (326 | ) | | | (549 | ) | | | (25 | ) |
| Cash and Cash Equivalents at End of Period | | $ | 470 | | | $ | 796 | | | $ | 1,345 | |
Operating Activities
Net Cash Flows from Operating Activities were $94 million in 2010. PSO produced Net Income of $73 million during the period and had noncash expense items of $105 million for Depreciation and Amortization and $93 million for Deferred Income Taxes. The $19 million outflow in Change in Other Noncurrent Assets was primarily the result of the deferral of January 2010 ice storm costs. 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 $24 million outflow from Accrued Taxes, Net was primarily due to an increa se in accrued tax benefits as a result of PSO’s 2010 federal net income tax operating loss. Items contributing to the net income tax operating loss included bonus depreciation and the favorable impact of a change in tax accounting method related to units of property. The $21 million outflow from Accounts Payable was primarily due to a decrease in affiliated payables. The $10 million outflow in Accounts Receivable, Net was primarily due to the refund anticipated from Parent as a result of PSO’s 2010 federal net income tax operating loss. The $88 million outflow from Fuel Over/Under-Recovery, Net was the result of returning previously over-recovered fuel costs to customers and higher fuel costs in relation to commission-approved fuel recovery rates.
Net Cash Flows from Operating Activities were $240 million in 2009. PSO produced Net Income of $76 million during the period and had noncash expense items of $110 million for Depreciation and Amortization and $56 million for Deferred Income Taxes. The other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items. The $81 million inflow from Accounts Receivable, Net was primarily due to receiving the SIA refund from the AEP East companies. The $16 million outflow from Accounts Payable was primarily due to decreases in customer accounts factored and purchased power payables. The $10 million outflow from Accrued Taxes, Net was due to an increase in accrued tax benefits resulting from a net income tax operating loss in 2009. The $59 million outflow from Fuel Over/Under-Recovery, Net was primarily due to refunding customers previously over-recovered fuel costs, including those associated with the SIA refund.
Net Cash Flows from Operating Activities were $168 million in 2008. PSO produced Net Income of $78 million during the period and had noncash expense items of $105 million for Depreciation and Amortization and $68 million for Deferred Income Taxes. PSO established a $74 million regulatory asset for an OCC order approving recovery of ice storm costs related to storms in January and December 2007. PSO recorded a Provision for SIA Refund of $52 million to its customers for off-system sales margins to be received from the AEP East companies as ordered by the FERC related to the SIA. 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 p ay cash, such as regulatory assets and liabilities. The activity in working capital relates to a number of items. The $89 million outflow from Accounts Payable was primarily due to a decrease in accounts payable accruals and purchased power payables. The $41 million change in Accounts Receivable, Net was primarily the result of the refund to be received from the AEP East companies related to the SIA. The $29 million inflow from Accrued Taxes, Net was the result of a refund for the 2007 overpayment of federal income taxes and increased accruals related to property and income taxes. The $47 million inflow from Fuel Over/Under-Recovery, Net resulted from revenues exceeding recoverable fuel costs.
Investing Activities
Net Cash Flows Used for Investing Activities in 2010, 2009 and 2008 were $133 million, $238 million and $233 million, respectively. Construction Expenditures of $195 million, $175 million and $286 million in 2010, 2009 and 2008, respectively, were primarily related to projects for improved generation, transmission and distribution service reliability, customer service work and storm restoration. In 2010 and 2009, PSO had a net decrease and increase, respectively, of $63 million in loans to the Utility Money Pool. In 2008, PSO had a net decrease of $51 million in loans to the Utility Money Pool.
Financing Activities
Net Cash Flows from Financing Activities were $38 million in 2010. PSO had a net increase of $91 million in borrowings from the Utility Money Pool. This inflow was partially offset by $51 million paid in dividends on common stock.
Net Cash Flows Used for Financing Activities were $2 million in 2009. PSO issued $250 million of Senior Unsecured Notes and $34 million of Pollution Control Bonds, partially offset by the retirement of $200 million of Senior Unsecured Notes. PSO had a net decrease of $70 million in borrowings from the Utility Money Pool. In addition, PSO paid $32 million in common stock dividends and received capital contributions from the Parent of $20 million.
Net Cash Flows from Financing Activities were $65 million in 2008. PSO had a net increase of $70 million in borrowings from the Utility Money Pool and received capital contributions from the Parent of $30 million. These inflows were partially offset by PSO’s repurchasing of $34 million of Pollution Control Bonds in May 2008.
In January 2011, PSO issued $250 million of 4.4% Senior Unsecured Notes due in 2021.
In January 2011, PSO gave notice to retire $200 million of 6% Senior Unsecured Notes due in 2032 on February 28, 2011.
CONTRACTUAL OBLIGATION INFORMATION
PSO’s contractual cash obligations include amounts reported on PSO’s Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes PSO’s contractual cash obligations at December 31, 2010:
| | Payments Due by Period |
| | |
| | | | | Less Than | | | | | | After | | |
| | Contractual Cash Obligations | | 1 year | | 2-3 years | | 4-5 years | | 5 years | | Total |
| | | | (in millions) |
| | Advances from Affiliates | | $ | 91.4 | | $ | - | | $ | - | | $ | - | | $ | 91.4 |
| | Interest on Fixed Rate Portion of Long-term Debt (a) | | | 54.8 | | | 106.0 | | | 103.3 | | | 631.6 | | | 895.7 |
| | Fixed Rate Portion of Long-term Debt (b) | | | 25.0 | | | 0.3 | | | 34.0 | | | 914.3 | | | 973.6 |
| | Capital Lease Obligations (c) | | | 5.4 | | | 7.8 | | | 4.2 | | | 4.1 | | | 21.5 |
| | Noncancelable Operating Leases (c) | | | 2.3 | | | 3.5 | | | 1.5 | | | 1.0 | | | 8.3 |
| | Fuel Purchase Contracts (d) | | | 256.6 | | | 113.8 | | | 30.1 | | | - | | | 400.5 |
| | Energy and Capacity Purchase Contracts (e) | | | 18.0 | | | 114.8 | | | 131.5 | | | 590.7 | | | 855.0 |
| | Construction Contracts for Capital Assets (f) | | | 36.0 | | | 53.9 | | | 44.8 | | | 118.9 | | | 253.6 |
| | Total | | $ | 489.5 | | $ | 400.1 | | $ | 349.4 | | $ | 2,260.6 | | $ | 3,499.6 |
| (a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2010 and do not reflect anticipated future refinancings, early redemptions or debt issuances. |
| (b) | See “Long-term Debt” section of Note 14. Represents principal only excluding interest. |
| (c) | See Note 13. |
| (d) | Represents contractual obligations to purchase coal, natural gas and other consumables as fuel for electric generation along with related transportation of the fuel. |
| (e) | Represents contractual obligations for energy and capacity purchase contracts. |
| (f) | Represents only capital assets for which PSO has signed contracts. Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs. |
PSO’s $9 million liability related to uncertainty in Income Taxes is not included above because management cannot reasonably estimate the cash flows by period.
PSO’s pension funding requirements are not included in the above table. As of December 31, 2010, management expects to make contributions to the pension plans totaling $5.4 million in 2011. Estimated contributions of $18 million in 2012 and $14.5 million in 2013 may vary significantly based on market returns, changes in actuarial assumptions and other factors. Based upon the benefit obligation and fair value of assets available to pay pension benefits, PSO’s pension plan obligation was 79.6% funded as of December 31, 2010.
As of December 31, 2010, PSO had no outstanding standby letters of credit or guarantees of performance.
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” beginning on page 405 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 Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 for a discussion of the adoption and impact of new accounting pronouncements.
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 405 for a discussion of risk management activities.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Public Service Company of Oklahoma:
We have audited the accompanying balance sheets of Public Service Company of Oklahoma (the "Company") as of December 31, 2010 and 2009, and the related statements of income, changes in common shareholder’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Public Service Company of Oklahoma as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Columbus, Ohio
February 25, 2011
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Public Service Company of Oklahoma (PSO) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. PSO’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of PSO’s internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on management’s assessment, PSO’s internal control over financial reporting was effective as of December 31, 2010.
This annual report does not include an attestation report of PSO’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit PSO to provide only management’s report in this annual report.
| PUBLIC SERVICE COMPANY OF OKLAHOMA | |
| STATEMENTS OF INCOME | |
| For the Years Ended December 31, 2010, 2009 and 2008 | |
| (in thousands) | |
| | | | | | | | | | |
| | | 2010 | | | 2009 | | | 2008 | |
| REVENUES | | | | | | | | | |
| Electric Generation, Transmission and Distribution | | $ | 1,246,916 | | | $ | 1,075,014 | | | $ | 1,549,490 | |
| Sales to AEP Affiliates | | | 23,528 | | | | 45,756 | | | | 101,602 | |
| Other Revenues | | | 3,218 | | | | 3,980 | | | | 4,853 | |
| TOTAL REVENUES | | | 1,273,662 | | | | 1,124,750 | | | | 1,655,945 | |
| | | | | | | | | | | | | |
| EXPENSES | | | | | | | | | | | | |
| Fuel and Other Consumables Used for Electric Generation | | | 373,317 | | | | 310,168 | | | | 774,089 | |
| Purchased Electricity for Resale | | | 187,106 | | | | 180,055 | | | | 270,536 | |
| Purchased Electricity from AEP Affiliates | | | 46,013 | | | | 19,331 | | | | 59,344 | |
| Other Operation | | | 222,396 | | | | 185,575 | | | | 208,930 | |
| Maintenance | | | 115,788 | | | | 108,020 | | | | 113,305 | |
| Deferral of Ice Storm Costs | | | - | | | | - | | | | (74,217 | ) |
| Depreciation and Amortization | | | 104,929 | | | | 110,149 | | | | 105,249 | |
| Taxes Other Than Income Taxes | | | 42,121 | | | | 41,144 | | | | 38,246 | |
| TOTAL EXPENSES | | | 1,091,670 | | | | 954,442 | | | | 1,495,482 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 181,992 | | | | 170,308 | | | | 160,463 | |
| | | | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | | | |
| Interest Income | | | 308 | | | | 1,879 | | | | 25,248 | |
| Carrying Costs Income | | | 3,145 | | | | 4,642 | | | | 10,138 | |
| Allowance for Equity Funds Used During Construction | | | 804 | | | | 1,787 | | | | 1,822 | |
| Interest Expense | | | (63,362 | ) | | | (59,093 | ) | | | (76,910 | ) |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAX EXPENSE | | | 122,887 | | | | 119,523 | | | | 120,761 | |
| | | | | | | | | | | | | |
| Income Tax Expense | | | 50,100 | | | | 43,921 | | | | 42,277 | |
| | | | | | | | | | | | | |
| NET INCOME | | | 72,787 | | | | 75,602 | | | | 78,484 | |
| | | | | | | | | | | | | |
| Preferred Stock Dividend Requirements | | | 200 | | | | 212 | | | | 212 | |
| | | | | | | | | | | | | |
| EARNINGS ATTRIBUTABLE TO COMMON STOCK | | $ | 72,587 | | | $ | 75,390 | | | $ | 78,272 | |
| | | | | | | | | | | | | |
| The common stock of PSO is wholly-owned by AEP. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
| PUBLIC SERVICE COMPANY OF OKLAHOMA |
| STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S |
| EQUITY AND COMPREHENSIVE INCOME (LOSS) |
| For the Years Ended December 31, 2010, 2009 and 2008 |
| (in thousands) |
| |
| | | | | | | | | | | | Accumulated | | |
| | | | | | | | | | | | Other | | |
| | | Common | | Paid-in | | Retained | | Comprehensive | | |
| | | Stock | | Capital | | Earnings | | Income (Loss) | | Total |
| TOTAL COMMON SHAREHOLDER'S EQUITY – | | | | | | | | | | | | | | | |
| | DECEMBER 31, 2007 | | $ | 157,230 | | $ | 310,016 | | $ | 174,539 | | $ | (887) | | $ | 640,898 |
| | | | | | | | | | | | | | | | |
| Adoption of Guidance for Split-Dollar Life Insurance | | | | | | | | | | | | | | | |
| | Accounting, Net of Tax of $596 | | | | | | | | | (1,107) | | | | | | (1,107) |
| Capital Contribution from Parent | | | | | | 30,000 | | | | | | | | | 30,000 |
| Preferred Stock Dividends | | | | | | | | | (212) | | | | | | (212) |
| SUBTOTAL – COMMON SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | 669,579 |
| | | | | | | | | | | | | | | | | |
| COMPREHENSIVE INCOME | | | | | | | | | | | | | | | |
| Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | |
| | | Cash Flow Hedges, Net of Tax of $99 | | | | | | | | | | | | 183 | | | 183 |
| NET INCOME | | | | | | | | | 78,484 | | | | | | 78,484 |
| TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 78,667 |
| | | | | | | | | | | | | | | | | | | |
| TOTAL COMMON SHAREHOLDER'S EQUITY – | | | | | | | | | | | | | | | |
| | DECEMBER 31, 2008 | | | 157,230 | | | 340,016 | | | 251,704 | | | (704) | | | 748,246 |
| | | | | | | | | | | | | | | | |
| Capital Contribution from Parent | | | | | | 20,000 | | | | | | | | | 20,000 |
| Common Stock Dividends | | | | | | | | | (32,000) | | | | | | (32,000) |
| Preferred Stock Dividends | | | | | | | | | (212) | | | | | | (212) |
| Gain on Reacquired Preferred Stock | | | | | | 1 | | | | | | | | | 1 |
| Other Changes in Common Shareholder's Equity | | | | | | 4,214 | | | (4,214) | | | | | | - |
| SUBTOTAL – COMMON SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | 736,035 |
| | | | | | | | | | | | | | | | |
| COMPREHENSIVE INCOME | | | | | | | | | | | | | | | |
| Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | |
| | | Cash Flow Hedges, Net of Tax of $57 | | | | | | | | | | | | 105 | | | 105 |
| NET INCOME | | | | | | | | | 75,602 | | | | | | 75,602 |
| TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 75,707 |
| | | | | | | | | | | | | | | | |
| TOTAL COMMON SHAREHOLDER'S EQUITY – | | | | | | | | | | | | | | | |
| | DECEMBER 31, 2009 | | | 157,230 | | | 364,231 | | | 290,880 | | | (599) | | | 811,742 |
| | | | | | | | | | | | | | | | |
| Common Stock Dividends | | | | | | | | | (51,026) | | | | | | (51,026) |
| Preferred Stock Dividends | | | | | | | | | (200) | | | | | | (200) |
| Gain on Reacquired Preferred Stock | | | | | | 76 | | | | | | | | | 76 |
| SUBTOTAL – COMMON SHAREHOLDER'S EQUITY | | | | | | | | | | | | | | | 760,592 |
| | | | | | | | | | | | | | | | |
| COMPREHENSIVE INCOME | | | | | | | | | | | | | | | |
| Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | |
| | | Cash Flow Hedges, Net of Tax of $4,896 | | | | | | | | | | | | 9,093 | | | 9,093 |
| NET INCOME | | | | | | | | | 72,787 | | | | | | 72,787 |
| TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | 81,880 |
| | | | | | | | | | | | | | | | |
| TOTAL COMMON SHAREHOLDER'S EQUITY – | | | | | | | | | | | | | | | |
| | DECEMBER 31, 2010 | | $ | 157,230 | | $ | 364,307 | | $ | 312,441 | | $ | 8,494 | | $ | 842,472 |
| |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. |
| PUBLIC SERVICE COMPANY OF OKLAHOMA | |
| BALANCE SHEETS | |
| ASSETS | |
| December 31, 2010 and 2009 | |
| (in thousands) | |
| | |
| | | 2010 | | | 2009 | |
| CURRENT ASSETS | | | | | | |
| Cash and Cash Equivalents | | $ | 470 | | | $ | 796 | |
| Advances to Affiliates | | | - | | | | 62,695 | |
| Accounts Receivable: | | | | | | | | |
| Customers | | | 43,049 | | | | 38,239 | |
| Affiliated Companies | | | 65,070 | | | | 59,096 | |
| Miscellaneous | | | 5,497 | | | | 7,242 | |
| Allowance for Uncollectible Accounts | | | (971 | ) | | | (304 | ) |
| Total Accounts Receivable | | | 112,645 | | | | 104,273 | |
| Fuel | | | 20,176 | | | | 20,892 | |
| Materials and Supplies | | | 46,247 | | | | 44,914 | |
| Risk Management Assets | | | 14,225 | | | | 2,376 | |
| Deferred Income Tax Benefits | | | - | | | | 26,335 | |
| Accrued Tax Benefits | | | 38,589 | | | | 15,291 | |
| Regulatory Asset for Under-Recovered Fuel Costs | | | 37,262 | | | | - | |
| Prepayments and Other Current Assets | | | 9,416 | | | | 9,139 | |
| TOTAL CURRENT ASSETS | | | 279,030 | | | | 286,711 | |
| | | | | | | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
| Electric: | | | | | | | | |
| Generation | | | 1,330,368 | | | | 1,300,069 | |
| Transmission | | | 663,994 | | | | 617,291 | |
| Distribution | | | 1,686,470 | | | | 1,596,355 | |
| Other Property, Plant and Equipment | | | 235,406 | | | | 228,705 | |
| Construction Work in Progress | | | 59,091 | | | | 67,138 | |
| Total Property, Plant and Equipment | | | 3,975,329 | | | | 3,809,558 | |
| Accumulated Depreciation and Amortization | | | 1,255,064 | | | | 1,220,177 | |
| TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 2,720,265 | | | | 2,589,381 | |
| | | | | | | | | |
| OTHER NONCURRENT ASSETS | | | | | | | | |
| Regulatory Assets | | | 263,545 | | | | 279,185 | |
| Long-term Risk Management Assets | | | 252 | | | | 50 | |
| Deferred Charges and Other Noncurrent Assets | | | 20,979 | | | | 13,880 | |
| TOTAL OTHER NONCURRENT ASSETS | | | 284,776 | | | | 293,115 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 3,284,071 | | | $ | 3,169,207 | |
| | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
| PUBLIC SERVICE COMPANY OF OKLAHOMA | |
| BALANCE SHEETS | |
| LIABILITIES AND SHAREHOLDERS' EQUITY | |
| December 31, 2010 and 2009 | |
| | | | | | | |
| | | 2010 | | | 2009 | |
| | | (in thousands) | |
| CURRENT LIABILITIES | | | | | | |
| Advances from Affiliates | | $ | 91,382 | | | $ | - | |
| Accounts Payable: | | | | | | | | |
| General | | | 69,155 | | | | 76,895 | |
| Affiliated Companies | | | 53,179 | | | | 71,099 | |
| Long-term Debt Due Within One Year – Nonaffiliated | | | 25,000 | | | | - | |
| Risk Management Liabilities | | | 922 | | | | 2,579 | |
| Customer Deposits | | | 41,217 | | | | 42,002 | |
| Accrued Taxes | | | 25,390 | | | | 19,471 | |
| Regulatory Liability for Over-Recovered Fuel Costs | | | - | | | | 51,087 | |
| Other Current Liabilities | | | 47,333 | | | | 60,905 | |
| TOTAL CURRENT LIABILITIES | | | 353,578 | | | | 324,038 | |
| | | | | | | | | |
| NONCURRENT LIABILITIES | | | | | | | | |
| Long-term Debt – Nonaffiliated | | | 946,186 | | | | 968,121 | |
| Long-term Risk Management Liabilities | | | 197 | | | | 144 | |
| Deferred Income Taxes | | | 660,783 | | | | 588,768 | |
| Regulatory Liabilities and Deferred Investment Tax Credits | | | 336,961 | | | | 326,931 | |
| Employee Benefits and Pension Obligations | | | 98,107 | | | | 107,748 | |
| Deferred Credits and Other Noncurrent Liabilities | | | 40,905 | | | | 36,457 | |
| TOTAL NONCURRENT LIABILITIES | | | 2,083,139 | | | | 2,028,169 | |
| | | | | | | | | |
| TOTAL LIABILITIES | | | 2,436,717 | | | | 2,352,207 | |
| | | | | | | | | |
| Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 4,882 | | | | 5,258 | |
| | | | | | | | | |
| Rate Matters (Note 4) | | | | | | | | |
| Commitments and Contingencies (Note 6) | | | | | | | | |
| | | | | | | | | |
| 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 | | | 312,441 | | | | 290,880 | |
| Accumulated Other Comprehensive Income (Loss) | | | 8,494 | | | | (599 | ) |
| TOTAL COMMON SHAREHOLDER’S EQUITY | | | 842,472 | | | | 811,742 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY | | $ | 3,284,071 | | | $ | 3,169,207 | |
| | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
| PUBLIC SERVICE COMPANY OF OKLAHOMA | |
| STATEMENTS OF CASH FLOWS | |
| For the Years Ended December 31, 2010, 2009 and 2008 | |
| (in thousands) | |
| | |
| | | 2010 | | | 2009 | | | 2008 | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net Income | | $ | 72,787 | | | $ | 75,602 | | | $ | 78,484 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | | | | | |
| Depreciation and Amortization | | | 104,929 | | | | 110,149 | | | | 105,249 | |
| Deferred Income Taxes | | | 92,695 | | | | 56,029 | | | | 67,874 | |
| Provision for SIA Refund | | | - | | | | - | | | | 52,100 | |
| Carrying Costs Income | | | (3,145 | ) | | | (4,642 | ) | | | (10,138 | ) |
| Deferral of Ice Storm Costs | | | - | | | | - | | | | (74,217 | ) |
| Allowance for Equity Funds Used During Construction | | | (804 | ) | | | (1,787 | ) | | | (1,822 | ) |
| Mark-to-Market of Risk Management Contracts | | | 160 | | | | 1,791 | | | | 5,151 | |
| Fuel Over/Under-Recovery, Net | | | (88,349 | ) | | | (59,462 | ) | | | 46,553 | |
| Unrealized Forward Commitments, Net | | | 46 | | | | (1,928 | ) | | | (5,263 | ) |
| Change in Other Noncurrent Assets | | | (19,325 | ) | | | 7,713 | | | | 6,117 | |
| Change in Other Noncurrent Liabilities | | | 3,764 | | | | 625 | | | | (6,774 | ) |
| Changes in Certain Components of Working Capital: | | | | | | | | | | | | |
| Accounts Receivable, Net | | | (10,094 | ) | | | 81,446 | | | | (40,725 | ) |
| Fuel, Materials and Supplies | | | (617 | ) | | | 5,301 | | | | (4,022 | ) |
| Margin Deposits | | | 217 | | | | 499 | | | | 8,093 | |
| Accounts Payable | | | (20,601 | ) | | | (16,431 | ) | | | (89,413 | ) |
| Accrued Taxes, Net | | | (23,605 | ) | | | (10,230 | ) | | | 28,506 | |
| Other Current Assets | | | 4,229 | | | | (6,426 | ) | | | 491 | |
| Other Current Liabilities | | | (18,341 | ) | | | 1,404 | | | | 1,712 | |
| Net Cash Flows from Operating Activities | | | 93,946 | | | | 239,653 | | | | 167,956 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction Expenditures | | | (194,896 | ) | | | (175,122 | ) | | | (285,826 | ) |
| Change in Other Temporary Investments, Net | | | 3 | | | | - | | | | 5 | |
| Change in Advances to Affiliates, Net | | | 62,695 | | | | (62,695 | ) | | | 51,202 | |
| Acquisitions of Assets | | | (2,819 | ) | | | (2,646 | ) | | | (1,409 | ) |
| Proceeds from Sales of Assets | | | 2,448 | | | | 2,488 | | | | 2,564 | |
| Net Cash Flows Used for Investing Activities | | | (132,569 | ) | | | (237,975 | ) | | | (233,464 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Capital Contribution from Parent | | | - | | | | 20,000 | | | | 30,000 | |
| Issuance of Long-term Debt – Nonaffiliated | | | 2,240 | | | | 280,732 | | | | - | |
| Change in Advances from Affiliates, Net | | | 91,382 | | | | (70,308 | ) | | | 70,308 | |
| Retirement of Long-term Debt – Nonaffiliated | | | - | | | | (200,000 | ) | | | (33,700 | ) |
| Retirement of Cumulative Preferred Stock | | | (300 | ) | | | (2 | ) | | | - | |
| Principal Payments for Capital Lease Obligations | | | (3,991 | ) | | | (1,485 | ) | | | (1,551 | ) |
| Dividends Paid on Common Stock | | | (51,026 | ) | | | (32,000 | ) | | | - | |
| Dividends Paid on Cumulative Preferred Stock | | | (200 | ) | | | (212 | ) | | | (212 | ) |
| Other Financing Activities | | | 192 | | | | 1,048 | | | | 638 | |
| Net Cash Flows from (Used For) Financing Activities | | | 38,297 | | | | (2,227 | ) | | | 65,483 | |
| | | | | | | | | | | | | |
| Net Decrease in Cash and Cash Equivalents | | | (326 | ) | | | (549 | ) | | | (25 | ) |
| Cash and Cash Equivalents at Beginning of Period | | | 796 | | | | 1,345 | | | | 1,370 | |
| Cash and Cash Equivalents at End of Period | | $ | 470 | | | $ | 796 | | | $ | 1,345 | |
| | | | | | | | | | | | | |
| SUPPLEMENTARY INFORMATION | | | | | | | | | | | | |
| Cash Paid for Interest, Net of Capitalized Amounts | | $ | 57,970 | | | $ | 71,135 | | | $ | 53,132 | |
| Net Cash Paid (Received) for Income Taxes | | | (16,770 | ) | | | 1,040 | | | | (50,022 | ) |
| Noncash Acquisitions Under Capital Leases | | | 13,794 | | | | 3,478 | | | | 1,008 | |
| Construction Expenditures Included in Accounts Payable at December 31, | | | 6,842 | | | | 11,901 | | | | 18,004 | |
| SIA Refund Included in Accounts Receivable at December 31, | | | - | | | | - | | | | 72,311 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
PUBLIC SERVICE COMPANY OF OKLAHOMA
INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The notes to PSO’s financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to PSO. The footnotes begin on page 246.
| | Footnote Reference |
| | |
| Organization and Summary of Significant Accounting Policies | Note 1 |
| New Accounting Pronouncements and Extraordinary Item | Note 2 |
| Rate Matters | Note 4 |
| Effects of Regulation | Note 5 |
| Commitments, Guarantees and Contingencies | Note 6 |
| Benefit Plans | Note 8 |
| Business Segments | Note 9 |
| Derivatives and Hedging | Note 10 |
| Fair Value Measurements | Note 11 |
| Income Taxes | Note 12 |
| Leases | Note 13 |
| Financing Activities | Note 14 |
| Related Party Transactions | Note 15 |
| Property, Plant and Equipment | Note 16 |
| Cost Reduction Initiatives | Note 17 |
| Unaudited Quarterly Financial Information | Note 18 |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
| SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | |
| SELECTED CONSOLIDATED FINANCIAL DATA | |
| (in thousands) | |
| | |
| | | | 2010 (a) | | 2009 | | 2008 | | 2007 | | 2006 | |
| STATEMENTS OF INCOME DATA | | | | | | | | | | | | | | | |
| Total Revenues | $ | 1,523,534 | | $ | 1,389,302 | | $ | 1,554,762 | | $ | 1,483,462 | | $ | 1,431,839 | |
| | | | | | | | | | | | | | | | | | |
| Operating Income | $ | 248,797 | | $ | 162,512 | | $ | 172,645 | | $ | 134,702 | | $ | 189,618 | |
| | | | | | | | | | | | | | | | | | |
| Income Before Extraordinary Loss | $ | 146,684 | | $ | 122,528 | | $ | 96,445 | | $ | 69,771 | | $ | 94,591 | |
| Extraordinary Loss, Net of Tax | | - | | | (5,325) | (b) | | - | | | - | | | - | |
| Net Income | | 146,684 | | | 117,203 | | | 96,445 | | | 69,771 | | | 94,591 | |
| Less: Net Income Attributable to | | | | | | | | | | | | | | | |
| | Noncontrolling Interest | | 4,093 | | | 3,130 | | | 3,691 | | | 3,507 | | | 2,868 | |
| Net Income Attributable to SWEPCo | | | | | | | | | | | | | | | |
| | Shareholders | | 142,591 | | | 114,073 | | | 92,754 | | | 66,264 | | | 91,723 | |
| Less: Preferred Stock Dividend | | | | | | | | | | | | | | | |
| | Requirements | | 229 | | | 229 | | | 229 | | | 229 | | | 229 | |
| Earnings Attributable to SWEPCo | | | | | | | | | | | | | | | |
| | Common Shareholder | $ | 142,362 | | $ | 113,844 | | $ | 92,525 | | $ | 66,035 | | $ | 91,494 | |
| | | | | | | | | | | | | | | | | | |
| BALANCE SHEETS DATA | | | | | | | | | | | | | | | |
| Total Property, Plant and Equipment | $ | 6,556,077 | | $ | 6,064,895 | | $ | 5,576,528 | | $ | 4,876,912 | | $ | 4,328,247 | |
| Accumulated Depreciation and Amortization | | 2,130,351 | | | 2,086,333 | | | 2,014,154 | | | 1,939,044 | | | 1,834,145 | |
| Total Property, Plant and Equipment – | | | | | | | | | | | | | | | |
| | Net | $ | 4,425,726 | | $ | 3,978,562 | | $ | 3,562,374 | | $ | 2,937,868 | | $ | 2,494,102 | |
| | | | | | | | | | | | | | | | | | |
| Total Assets | $ | 5,243,567 | | $ | 4,640,033 | | $ | 4,253,085 | | $ | 3,488,386 | | $ | 3,175,071 | |
| | | | | | | | | | | | | | | | | | |
| Total Common Shareholder's Equity | $ | 1,666,988 | | $ | 1,524,126 | | $ | 1,248,653 | | $ | 972,955 | | $ | 821,202 | |
| | | | | | | | | | | | | | | | | | |
| Cumulative Preferred Stock Not Subject to | | | | | | | | | | | | | | | |
| | Mandatory Redemption | $ | 4,696 | | $ | 4,697 | | $ | 4,697 | | $ | 4,697 | | $ | 4,697 | |
| | | | | | | | | | | | | | | | | | |
| Noncontrolling Interest | $ | 361 | | $ | 31 | | $ | 276 | | $ | 1,687 | | $ | ��1,815 | |
| | | | | | | | | | | | | | | | | | |
| Long-term Debt (c) | $ | 1,769,520 | (d) | $ | 1,474,153 | | $ | 1,478,149 | (d) | $ | 1,197,217 | (d) | $ | 729,006 | |
| | | | | | | | | | | | | | | | | | |
| Obligations Under Capital Leases (c) | $ | 128,664 | | $ | 148,661 | (e) | $ | 112,725 | (e) | $ | 100,320 | (e) | $ | 84,715 | |
| (a) | Prospectively adopted the “Consolidation” accounting guidance effective January 1, 2010 and began accounting for DHLC under the equity method of accounting. |
| (b) | Reflects the re-application of the generation portion of Texas’ retail jurisdiction in accordance with the accounting guidance for “Regulated Operations.” See “SWEPCo Texas Restructuring” in “Extraordinary Item” section of Note 2. |
| (c) | Includes portion due within one year. |
| (d) | Increased primarily due to the construction of new generation. |
| (e) | Increased primarily due to new leases for coal handling equipment. |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
EXECUTIVE OVERVIEW
Company Overview
As a public utility, SWEPCo engages in the generation and purchase of electric power, and the subsequent sale, transmission and distribution of that power to approximately 520,000 retail customers in its service territory in northeastern and panhandle of Texas, northwestern Louisiana and western Arkansas. SWEPCo consolidates its wholly-owned subsidiary, Southwest Arkansas Utilities Corporation. See Note 2 for a discussion of the deconsolidation of DHLC effective January 1, 2010. SWEPCo also consolidates Sabine Mining Company, a variable interest entity. SWEPCo sells electric power at wholesale to other utilities, municipalities and electric cooperatives.
SWEPCo, as a member of the CSW Operating Agreement, is compensated for energy delivered to the other member based upon the delivering member’s incremental cost plus a portion of the savings realized by the purchasing member that avoids the use of more costly alternatives. PSO and SWEPCo share the revenues and costs for sales to neighboring utilities and power marketers made by AEPSC on their behalf based upon the relative magnitude of the energy each company provides to make such sales. SWEPCo shares these margins with its customers.
Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and gas risk management activities based upon the location of such activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP generally accruing to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among the AEP East companies, PSO and SWEPCo in proportion to the marketing realization directly assigned to each zone for the current month plus the preceding eleven months.
AEPSC conducts power, gas, coal and emission allowance risk management activities on SWEPCo’s behalf. SWEPCo shares in the revenues and expenses associated with these risk management activities, as described in the preceding paragraph, with the AEP East companies and PSO. Power and gas risk management activities are allocated based on the CSW Operating Agreement and the SIA. SWEPCo shares in coal and emission allowance risk management activities based on its proportion of fossil fuels burned by the AEP System. Risk management activities primarily involve the purchase and sale of electricity under physical forward contracts at fixed and variable prices and to a lesser extent gas, coal and emission allowances. The electricity, gas, coal and emission allowance contracts includ e physical transactions, OTC options and financially-settled swaps and exchange-traded futures and options. AEPSC settles the majority of the physical forward contracts by entering into offsetting contracts.
SWEPCo is jointly and severally liable for activity conducted by AEPSC on the behalf of the AEP East companies, PSO and SWEPCo related to purchase power and sale activity pursuant to the SIA.
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 4.
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 cost $1.3 billion, excluding AFUDC, plus an additional $125 million for transmission, excluding AFUDC. The APSC, LPSC and PUCT approved SWEPCo’s original application to build the Turk Plant. Various proceedings are pending that challenge the Turk Plant’s construction, its approved wetlands and air permits and its transmission line certificate of environmental compatibility and public need. See “Turk Plant” section of Note 4.
Litigation 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. 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 405 for additional discussion of relevant factors.
RESULTS OF OPERATIONS
KWH Sales/Degree Days
| Summary of KWH Energy Sales |
| | | | | | | | | | |
| | | Years Ended December 31, |
| | 2010 | | 2009 | | 2008 |
| | | (in millions of KWH) |
| Retail: | | | | | | | | |
| | Residential | | 6,361 | | | 5,587 | | | 5,694 |
| | Commercial | | 6,117 | | | 5,957 | | | 5,994 |
| | Industrial | | 5,254 | | | 4,460 | | | 5,402 |
| | Miscellaneous | | 81 | | | 82 | | | 82 |
| Total Retail | | 17,813 | | | 16,086 | | | 17,172 |
| | | | | | | | | |
| Wholesale | | 7,333 | | | 6,527 | | | 6,395 |
| | | | | | | | | |
| Total KWHs | | 25,146 | | | 22,613 | | | 23,567 |
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 |
| | | | | | | | | | | |
| | | | Years Ended December 31, |
| | | | 2010 | | 2009 | | 2008 |
| | | | (in degree days) |
| | | | | | | | | | | |
| | Actual - Heating (a) | | 1,543 | | | 1,270 | | | 1,325 |
| | Normal - Heating (b) | | 1,253 | | | 1,263 | | | 1,281 |
| | | | | | | | | | | |
| | Actual - Cooling (c) | | 2,592 | | | 1,956 | | | 2,031 |
| | Normal - Cooling (b) | | 2,213 | | | 2,231 | | | 2,221 |
| | | | | | | | | | | |
| | (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. |
| 2010 Compared to 2009 | |
| | | | |
| Reconciliation of Year Ended December 31, 2009 to Year Ended December 31, 2010 | |
| Income Before Extraordinary Loss | |
| (in millions) | |
| | | | |
| Year Ended December 31, 2009 | | $ | 123 | |
| | | | | |
| Changes in Gross Margin: | | | | |
| Retail Margins (a) | | | 104 | |
| Off-system Sales | | | 1 | |
| Transmission Revenues | | | 1 | |
| Other Revenues | | | (42 | ) |
| Total Change in Gross Margin | | | 64 | |
| | | | | |
| Total Expenses and Other: | | | | |
| Other Operation and Maintenance | | | 7 | |
| Depreciation and Amortization | | | 18 | |
| Taxes Other Than Income Taxes | | | (3 | ) |
| Other Income | | | (1 | ) |
| Interest Expense | | | (16 | ) |
| Equity Earnings of Unconsolidated Subsidiaries | | | 2 | |
| Total Expenses and Other | | | 7 | |
| | | | | |
| Income Tax Expense | | | (47 | ) |
| | | | | |
| Year Ended December 31, 2010 | | $ | 147 | |
| (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 $104 million primarily due to: |
| | · | A $42 million increase in base rates in Arkansas and Texas. This increase in Retail Margins had corresponding increases of $9 million related to riders/trackers recognized in other expense items. |
| | · | A $25 million increase in weather-related usage primarily due to a 33% increase in cooling degree days and a 21% increase in heating degree days. |
| | · | A $16 million increase in fuel recovery primarily due to lower capacity costs and increased wholesale fuel recovery. |
| | · | A $14 million increase in industrial sales compared to the recessionary lows of 2009. |
| · | Other Revenues decreased $42 million primarily 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 discussed below. |
Total Expenses and Other and Income Tax Expense changed between years as follows:
| · | Other Operation and Maintenance expenses decreased $7 million primarily due to: |
| | · | A $34 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 Other Revenues discussed above. |
| | This decrease was partially offset by: |
| | · | A $30 million increase due to expenses related to cost reduction initiatives. In 2010, management conducted cost reduction initiatives to reduce both labor and non-labor expenses. |
| · | Depreciation and Amortization expenses decreased $18 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 the addition of the Stall Unit. |
| · | Interest Expense increased $16 million primarily due to increased long-term debt outstanding. |
| · | Income Tax Expense increased $47 million primarily due to an increase in pretax book income and the recording of federal income tax adjustments. |
| 2009 Compared to 2008 | |
| | | | |
| Reconciliation of Year Ended December 31, 2008 to Year Ended December 31, 2009 | |
| Income Before Extraordinary Loss | |
| (in millions) | |
| | | | |
| Year Ended December 31, 2008 | | $ | 96 | |
| | | | | |
| Changes in Gross Margin: | | | | |
| Retail Margins (a) | | | (32 | ) |
| Off-system Sales | | | 1 | |
| Transmission Revenues | | | 7 | |
| Other Revenues | | | (1 | ) |
| Total Change in Gross Margin | | | (25 | ) |
| | | | | |
| Total Expenses and Other: | | | | |
| Other Operation and Maintenance | | | 16 | |
| Taxes Other Than Income Taxes | | | (1 | ) |
| Other Income | | | (2 | ) |
| Interest Expense | | | 23 | |
| Total Expenses and Other | | | 36 | |
| | | | | |
| Income Tax Expense | | | 16 | |
| | | | | |
| Year Ended December 31, 2009 | | $ | 123 | |
| (a) | Includes firm wholesale sales to municipals and cooperatives. | |
The major components of the decrease in Gross Margin, defined as revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power were as follows:
| · | Retail Margins decreased $32 million primarily due to the following: |
| | · | A $22 million decrease due to the net favorable effect of the recognition of off-system sales margins as ordered by the FERC in November 2008. |
| | · | A $12 million decrease in wholesale fuel recovery. |
| | · | A $12 million decrease in industrial sales due to reduced operating levels and suspended operations by certain large industrial customers in SWEPCo’s service territory. |
| | · | A $5 million net impairment of a fuel regulatory asset related to deferred mining costs in Arkansas. |
| | These decreases were partially offset by: |
| | · | A $13 million increase in wholesale and municipal revenue primarily due to higher prices and the annual true-up for formula rate customers. |
| | · | An $8 million increase in rate relief related to the Louisiana Formula Rate Plan. |
| · | Transmission Revenues increased $7 million primarily due to higher rates in the SPP region. |
Total Expenses and Other and Income Tax Expense changed between years as indicated:
| · | Other Operation and Maintenance expenses decreased $16 million primarily due to the following: |
| | · | An $11 million decrease in distribution expenses associated with the 2008 storm restoration expenses from Hurricanes Ike and Gustav. |
| | · | A $2 million decrease in expenses for coal deliveries from SWEPCo’s mining subsidiary, DHLC. |
| | · | A $2 million decrease resulting from reduced sale of receivable expense due to decreased revenues. |
| · | Other Income decreased $2 million primarily due to the following: |
| | · | A $26 million decrease in interest income from the AEP East companies for the refund in 2008 of off-system sales margins in accordance with the FERC’s order related to SIA. |
| | · | An $8 million decrease in interest income primarily resulting from fuel recovery and decreased lending to affiliated companies. |
| | These decreases were partially offset by: |
| | · | A $32 million increase in the equity component of AFUDC primarily 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 April 2009. |
| · | Interest Expense decreased $23 million primarily due to the following: |
| | · | Interest expense of $16 million to customers for off-system sales margins in accordance with the FERC’s 2008 order related to the SIA. |
| | · | A $10 million increase in the debt component of AFUDC due to new generation projects at the Turk Plant and Stall Unit. |
| | · | A $2 million decrease in interest expense due to a decrease in short-term debt outstanding. |
| | These decreases were partially offset by: |
| | · | A $5 million increase in interest expense due to an increase in long-term debt outstanding during the first six months of 2009. |
| · | Income Tax Expense decreased $16 million primarily due to the regulatory accounting treatment of state income taxes and other book/tax differences which are accounted for on a flow-through basis and a tax loss benefit from Parent. |
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 405 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 2010, 2009 and 2008 were as follows:
| | | Years Ended December 31, | |
| | | 2010 | | | 2009 | | | 2008 | |
| | | (in thousands) | |
| Cash and Cash Equivalents at Beginning of Period | | $ | 1,661 | | | $ | 1,910 | | | $ | 1,742 | |
| Cash Flows from (Used for): | | | | | | | | | | | | |
| Operating Activities | | | 272,951 | | | | 410,820 | | | | 224,210 | |
| Investing Activities | | | (553,170 | ) | | | (556,487 | ) | | | (692,345 | ) |
| Financing Activities | | | 280,072 | | | | 145,418 | | | | 468,303 | |
| Net Increase (Decrease) in Cash and Cash Equivalents | | | (147 | ) | | | (249 | ) | | | 168 | |
| Cash and Cash Equivalents at End of Period | | $ | 1,514 | | | $ | 1,661 | | | $ | 1,910 | |
Operating Activities
Net Cash Flows from Operating Activities were $273 million in 2010. SWEPCo produced Net Income of $147 million during the period and had noncash items of $127 million for Depreciation and Amortization and $82 million for Deferred Income Taxes, partially offset by $46 million in Allowance for Equity Funds Used During Construction. SWEPCo contributed $29 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 $23 million outflow from Accounts Payable was primarily due t o a decrease in fuel costs and purchased power payables. The $22 million outflow from Accounts Receivable, Net was primarily due to the refund anticipated from Parent as a result of SWEPCo’s 2010 federal net income tax operating loss. Items contributing to the net income tax operating loss included bonus depreciation and the favorable impact of a change in tax accounting method related to units of property. The $21 million inflow from Fuel, Materials and Supplies was primarily due to lower coal inventories at the Flint Creek and Welsh Plants. The $19 million outflow from Accrued Taxes, Net was primarily due to an increase in accrued tax benefits as a result of SWEPCo’s 2010 federal net income tax operating loss.
Net Cash Flows from Operating Activities were $411 million in 2009. SWEPCo produced Net Income of $117 million during the period and had noncash expense items of $145 million for Depreciation and Amortization and $28 million for Deferred Income Taxes, partially offset by $47 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 $113 million inflow from Accounts Receivable, Net was a result of receiving the SIA refund from the AEP East companies and bill ed sale of receivables. The $41 million inflow from Accounts Payable was due to a new gas transportation contract, fuel received but not billed and unbilled sale of receivables. The $26 million outflow from Fuel, Materials and Supplies was due to higher coal inventories at Sabine Mining Company. The $25 million outflow from Accrued Taxes, Net was the result of tax payments for prior year liabilities and decreased accruals related to property and income taxes. The $68 million inflow from Fuel Over/Under-Recovery, Net was due to higher fuel cost recovery in Arkansas and Texas.
Net Cash Flows from Operating Activities were $224 million in 2008. SWEPCo produced Net Income of $96 million during the period and had noncash expense items of $145 million for Depreciation and Amortization and $62 million for Deferred Income Taxes. SWEPCo recorded a Provision for SIA Refund of $54 million to its customers for off-system sales margins to be received from the AEP East companies as ordered by the FERC related to the SIA. 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 $52 million out flow from Accounts Receivable, Net was primarily the result of the anticipated refund from the AEP East companies related to the SIA. The $36 million outflow from Accounts Payable was primarily due to a decrease in purchased power payables. The $25 million outflow from Fuel, Materials and Supplies was primarily due to higher coal and fuel-related costs. The $87 million outflow from Fuel Over/Under-Recovery, Net was the result of higher fuel costs.
Investing Activities
Net Cash Flows Used for Investing Activities in 2010, 2009 and 2008 were $553 million, $556 million and $692 million, respectively. Construction Expenditures of $420 million, $597 million and $692 million in 2010, 2009 and 2008, respectively, were primarily related to new generation projects at the Turk Plant and Stall Unit. In 2010, SWEPCo acquired the Valley Electric Membership Corporation for $102 million and increased loans to the Utility Money Pool by $34 million. In 2009, SWEPCo increased loans to the Utility Money Pool by $35 million, acquired the Red River Mining Company for $16 million and purchased 50% of the Oxbow Lignite Mining Company, LLC membership interest for $13 million. These outflows in 2009 were partially offset by $106 million in proceeds from sales of assets primarily relating to the sale of a portion of Turk Plant to joint owners.
Financing Activities
Net Cash Flows from Financing Activities were $280 million in 2010. SWEPCo issued $350 million of Senior Unsecured Notes and $54 million of Pollution Control Bonds. These increases were partially offset by the retirement of $54 million of Pollution Control Bonds and $50 million of Notes Payable – Affiliated.
Net Cash Flows from Financing Activities were $145 million in 2009. During the year, SWEPCo received capital contributions from the Parent of $143 million.
Net Cash Flows from Financing Activities were $468 million in 2008. SWEPCo issued $400 million of Senior Unsecured Notes and received capital contributions from the Parent of $200 million. These increases were partially offset by the retirement of $160 million of Long-term Debt – Nonaffiliated.
CONTRACTUAL OBLIGATION INFORMATION
SWEPCo’s contractual cash obligations include amounts reported on SWEPCo’s Consolidated Balance Sheets and other obligations disclosed in the footnotes. The following table summarizes SWEPCo’s contractual cash obligations at December 31, 2010:
| | Payments Due by Period |
| | |
| | | | | Less Than | | | | | | After | | |
| | Contractual Cash Obligations | | 1 year | | 2-3 years | | 4-5 years | | 5 years | | Total |
| | | | (in millions) |
| | Short-term Debt (a) | | $ | 6.2 | | $ | - | | $ | - | | $ | - | | $ | 6.2 |
| | Interest on Fixed Rate Portion of Long-term | | | | | | | | | | | | | | | |
| | | Debt (b) | | | 102.4 | | | 198.4 | | | 194.6 | | | 711.0 | | | 1,206.4 |
| | Fixed Rate Portion of Long-term Debt (c) | | | 41.1 | | | 20.0 | | | 303.5 | | | 1,406.7 | | | 1,771.3 |
| | Capital Lease Obligations (d) | | | 22.3 | | | 42.3 | | | 36.1 | | | 78.5 | | | 179.2 |
| | Noncancelable Operating Leases (d) | | | 6.0 | | | 9.1 | | | 5.7 | | | 12.5 | | | 33.3 |
| | Fuel Purchase Contracts (e) | | | 257.1 | | | 321.2 | | | 76.6 | | | 80.2 | | | 735.1 |
| | Energy and Capacity Purchase Contracts (f) | | | 19.0 | | | 39.1 | | | 39.2 | | | 284.9 | | | 382.2 |
| | Construction Contracts for Capital Assets (g) | | | 172.0 | | | 201.2 | | | 105.3 | | | 110.7 | | | 589.2 |
| | Total | | $ | 626.1 | | $ | 831.3 | | $ | 761.0 | | $ | 2,684.5 | | $ | 4,902.9 |
| (a) | Represents principal only excluding interest. |
| (b) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2010 and do not reflect anticipated future refinancings, early redemptions or debt issuances. |
| (c) | See “Long-term Debt” section of Note 14. Represents principal only excluding interest. |
| (d) | See Note 13. |
| (e) | Represents contractual obligations to purchase coal, natural gas and other consumables as fuel for electric generation along with related transportation of the fuel. |
| (f) | Represents contractual obligations for energy and capacity purchase contracts. |
| (g) | Represents only capital assets for which SWEPCo has signed contracts. Actual payments are dependent upon and may vary significantly based upon the decision to build, regulatory approval schedules, timing and escalation of project costs. |
SWEPCo’s $14 million liability related to uncertainty in Income Taxes is not included above because management cannot reasonably estimate the cash flows by period.
SWEPCo’s pension funding requirements are not included in the above table. As of December 31, 2010, management expects to make contributions to the pension plans totaling $7.3 million in 2011. Estimated contributions of $16.3 million in 2012 and $13.2 million in 2013 may vary significantly based on market returns, changes in actuarial assumptions and other factors. Based upon the benefit obligation and fair value of assets available to pay pension benefits, SWEPCo’s pension plan obligation was 84.1% funded as of December 31, 2010.
In addition to the amounts disclosed in the contractual cash obligations table above, SWEPCo makes additional commitments in the normal course of business. SWEPCo’s commitments outstanding at December 31, 2010 under these agreements are summarized in the table below:
| | Amount of Commitment Expiration Per Period |
| | |
| | | | Less Than | | | | | | After | | |
| | Other Commercial Commitments | | 1 year | | 2-3 years | | 4-5 years | | 5 years | | Total |
| | | | (in millions) |
| | Standby Letters of Credit (a) | | $ | 4.4 | | $ | - | | $ | - | | $ | - | | $ | 4.4 |
| | Guarantees of the Performance of Outside Parties (b) | | | - | | | - | | | - | | | 65.0 | | | 65.0 |
| | Total | | $ | 4.4 | | $ | - | | $ | - | | $ | 65.0 | | $ | 69.4 |
| (a) | SWEPCo enters into standby letters of credit (LOCs) with third parties. These LOCs cover items such as insurance programs, security deposits, debt service reserves and variable rate Pollution Control Bonds. All of these LOCs were issued in SWEPCo’s ordinary course of business. There is no collateral held in relation to any guarantees in excess of SWEPCo’s ownership percentages. In the event any LOC is drawn, there is no recourse to third parties. The maximum future payments of these LOCs are $4.4 million maturing in June 2011. See “Letters of Credit” section of Note 6. |
| (b) | See "Guarantees of Third-Party Obligations" section of Note 6. |
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” beginning on page 405 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 Pronouncements” section of “Combined Management’s Discussion and Analysis of Registrant Subsidiaries” beginning on page 405 for a discussion of the adoption and impact of new accounting pronouncements.
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 405 for a discussion of risk management activities.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Southwestern Electric Power Company:
We have audited the accompanying consolidated balance sheets of Southwestern Electric Power Company Consolidated (the "Company") as of December 31, 2010 and 2009, and the related consolidated statements of income, changes in equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Southwestern Electric Power Company Consolidated as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, the Company adopted FASB Accounting Standards Update No. 2009-17, Consolidations (Topic 810): Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities, effective January 1, 2010.
/s/ Deloitte & Touche LLP
Columbus, Ohio
February 25, 2011
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Southwestern Electric Power Company Consolidated (SWEPCo) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. SWEPCo’s internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of SWEPCo’s internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on management’s assessment, SWEPCo’s internal control over financial reporting was effective as of December 31, 2010.
This annual report does not include an attestation report of SWEPCo’s registered public accounting firm regarding internal control over financial reporting pursuant to the Securities and Exchange Commission rules that permit SWEPCo to provide only management’s report in this annual report.
| SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | |
| CONSOLIDATED STATEMENTS OF INCOME | |
| For the Years Ended December 31, 2010, 2009 and 2008 | |
| (in thousands) | |
| | |
| | | 2010 | | | 2009 | | | 2008 | |
| REVENUES | | | | | | | | | |
| Electric Generation, Transmission and Distribution | | $ | 1,469,514 | | | $ | 1,315,056 | | | $ | 1,458,027 | |
| Sales to AEP Affiliates | | | 51,870 | | | | 29,318 | | | | 50,842 | |
| Lignite Revenues – Nonaffiliated | | | - | | | | 43,239 | | | | 44,366 | |
| Other Revenues | | | 2,150 | | | | 1,689 | | | | 1,527 | |
| TOTAL REVENUES | | | 1,523,534 | | | | 1,389,302 | | | | 1,554,762 | |
| | | | | | | | | | | | | |
| EXPENSES | | | | | | | | | | | | |
| Fuel and Other Consumables Used for Electric Generation | | | 587,058 | | | | 495,928 | | | | 523,361 | |
| Purchased Electricity for Resale | | | 125,064 | | | | 127,170 | | | | 164,466 | |
| Purchased Electricity from AEP Affiliates | | | 23,707 | | | | 42,712 | | | | 118,773 | |
| Other Operation | | | 245,504 | | | | 249,792 | | | | 260,186 | |
| Maintenance | | | 103,352 | | | | 105,602 | | | | 111,273 | |
| Depreciation and Amortization | | | 126,901 | | | | 145,144 | | | | 145,011 | |
| Taxes Other Than Income Taxes | | | 63,151 | | | | 60,442 | | | | 59,047 | |
| TOTAL EXPENSES | | | 1,274,737 | | | | 1,226,790 | | | | 1,382,117 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 248,797 | | | | 162,512 | | | | 172,645 | |
| | | | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | | | |
| Interest Income | | | 579 | | | | 1,286 | | | | 35,086 | |
| Allowance for Equity Funds Used During Construction | | | 45,646 | | | | 46,737 | | | | 14,908 | |
| Interest Expense | | | (86,538 | ) | | | (70,500 | ) | | | (93,150 | ) |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAX EXPENSE AND EQUITY | | | | | | | | | | | | |
| EARNINGS (LOSS) | | | 208,484 | | | | 140,035 | | | | 129,489 | |
| | | | | | | | | | | | | |
| Income Tax Expense | | | 64,214 | | | | 17,511 | | | | 33,041 | |
| Equity Earnings (Loss) of Unconsolidated Subsidiaries | | | 2,414 | | | | 4 | | | | (3 | ) |
| | | | | | | | | | | | | |
| INCOME BEFORE EXTRAORDINARY LOSS | | | 146,684 | | | | 122,528 | | | | 96,445 | |
| | | | | | | | | | | | | |
| EXTRAORDINARY LOSS, NET OF TAX | | | - | | | | (5,325 | ) | | | - | |
| | | | | | | | | | | | | |
| NET INCOME | | | 146,684 | | | | 117,203 | | | | 96,445 | |
| | | | | | | | | | | | | |
| Less: Net Income Attributable to Noncontrolling Interest | | | 4,093 | | | | 3,130 | | | | 3,691 | |
| | | | | | | | | | | | | |
| NET INCOME ATTRIBUTABLE TO SWEPCo SHAREHOLDERS | | | 142,591 | | | | 114,073 | | | | 92,754 | |
| | | | | | | | | | | | | |
| Less: Preferred Stock Dividend Requirements | | | 229 | | | | 229 | | | | 229 | |
| | | | | | | | | | | | | |
EARNINGS ATTRIBUTABLE TO SWEPCo COMMON SHAREHOLDER | | $ | 142,362 | | | $ | 113,844 | | | $ | 92,525 | |
| | | | | | | | | | | | | |
| The common stock of SWEPCo is wholly-owned by AEP. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
| SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED |
| CONSOLIDATED STATEMENTS OF CHANGES IN |
| EQUITY AND COMPREHENSIVE INCOME (LOSS) |
| For the Years Ended December 31, 2010, 2009 and 2008 |
| (in thousands) |
| | | | | | | | | | | | | | | | | | | |
| | | SWEPCo Common Shareholder | | | | | | |
| | | | | | | | | | | | Accumulated | | | | | |
| | | | | | | | | | | | Other | | | | | |
| | | Common | | Paid-in | | Retained | | Comprehensive | | Noncontrolling | | |
| | | Stock | | Capital | | Earnings | | Income (Loss) | | Interest | | Total |
| | | | | | | | | | | | | | | | | | | |
| TOTAL EQUITY – DECEMBER 31, 2007 | | $ | 135,660 | | $ | 330,003 | | $ | 523,731 | | $ | (16,439) | | $ | 1,687 | | $ | 974,642 |
| | | | | | | | | | | | | | | | | | | |
| Adoption of Guidance for Split-Dollar Life Insurance | | | | | | | | | | | | | | | | | | |
| | Accounting, Net of Tax of $622 | | | | | | | | | (1,156) | | | | | | | | | (1,156) |
| Adoption of Guidance for Fair Value Accounting, Net | | | | | | | | | | | | | | | | | | |
| | of Tax of $6 | | | | | | | | | 10 | | | | | | | | | 10 |
| Capital Contribution from Parent | | | | | | 200,000 | | | | | | | | | | | | 200,000 |
| Common Stock Dividends – Nonaffilated | | | | | | | | | | | | | | | (5,109) | | | (5,109) |
| Preferred Stock Dividends | | | | | | | | | (229) | | | | | | | | | (229) |
| SUBTOTAL – EQUITY | | | | | | | | | | | | | | | | | | 1,168,158 |
| | | | | | | | | | | | | | | | | | | | |
| COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | |
| Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | | | | |
| | | Cash Flow Hedges, Net of Tax of $56 | | | | | | | | | | | | 97 | | | 7 | | | 104 |
| | | Amortization of Pension and OPEB Deferred Costs, | | | | | | | | | | | | | | | | | | |
| | | | Net of Tax of $507 | | | | | | | | | | | | 941 | | | | | | 941 |
| | | Pension and OPEB Funded Status, Net of Tax of $9,003 | | | | | | | | | | | | (16,719) | | | | | | (16,719) |
| NET INCOME | | | | | | | | | 92,754 | | | | | | 3,691 | | | 96,445 |
| TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | 80,771 |
| | | | | | | | | | | | | | | | | | | | | | |
| 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 | | | | | | | | | | | | | | | (3,375) | | | (3,375) |
| Preferred Stock Dividends | | | | | | | | | (229) | | | | | | | | | (229) |
| Other Changes in Equity | | | | | | 2,476 | | | (2,476) | | | | | | | | | - |
| SUBTOTAL – EQUITY | | | | | | | | | | | | | | | | | | 1,387,825 |
| | | | | | | | | | | | | | | | | | | |
| COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | |
| Other Comprehensive Income, Net of Taxes: | | | | | | | | | | | | | | | | | | |
| | | Cash Flow Hedges, Net of Tax of $533 | | | | | | | | | | | | 989 | | | | | | 989 |
| | | Reapplication of Regulated Operations Accounting | | | | | | | | | | | | | | | | | | |
| | | | Guidance for Pensions, Net of Tax of $8,223 | | | | | | | | | | | | 15,271 | | | | | | 15,271 |
| | | Amortization of Pension and OPEB Deferred Costs, | | | | | | | | | | | | | | | | | | |
| | | | Net of Tax of $928 | | | | | | | | | | | | 1,724 | | | | | | 1,724 |
| | | Pension and OPEB Funded Status, Net of Tax of $617 | | | | | | | | | | | | 1,145 | | | | | | 1,145 |
| NET INCOME | | | | | | | | | 114,073 | | | | | | 3,130 | | | 117,203 |
| TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | 136,332 |
| | | | | | | | | | | | | | | | | | | |
| TOTAL EQUITY – DECEMBER 31, 2009 | | | 135,660 | | | 674,979 | | | 726,478 | | | (12,991) | | | 31 | | | 1,524,157 |
| | | | | | | | | | | | | | | | | | | |
| Common Stock Dividends – Nonaffiliated | | | | | | | | | | | | | | | (3,763) | | | (3,763) |
| Preferred Stock Dividends | | | | | | | | | (229) | | | | | | | | | (229) |
| SUBTOTAL – EQUITY | | | | | | | | | | | | | | | | | | 1,520,165 |
| | | | | | | | | | | | | | | | | | | |
| COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | |
| Other Comprehensive Income (Loss), Net of Taxes: | | | | | | | | | | | | | | | | | | |
| | | Cash Flow Hedges, Net of Tax of $401 | | | | | | | | | | | | 745 | | | | | | 745 |
| | | Amortization of Pension and OPEB Deferred Costs, | | | | | | | | | | | | | | | | | | |
| | | | Net of Tax of $505 | | | | | | | | | | | | 937 | | | | | | 937 |
| | | Pension and OPEB Funded Status, Net of Tax of $636 | | | | | | | | | | | | (1,182) | | | | | | (1,182) |
| NET INCOME | | | | | | | | | 142,591 | | | | | | 4,093 | | | 146,684 |
| TOTAL COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | 147,184 |
| | | | | | | | | | | | | | | | | | | |
| TOTAL EQUITY – DECEMBER 31, 2010 | | $ | 135,660 | | $ | 674,979 | | $ | 868,840 | | $ | (12,491) | | $ | 361 | | $ | 1,667,349 |
| |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. |
| SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | |
| CONSOLIDATED BALANCE SHEETS | |
| ASSETS | |
| December 31, 2010 and 2009 | |
| (in thousands) | |
| | |
| | | 2010 | | | 2009 | |
| CURRENT ASSETS | | | | | | |
| Cash and Cash Equivalents | | $ | 1,514 | | | $ | 1,661 | |
| Advances to Affiliates | | | 86,222 | | | | 34,883 | |
| Accounts Receivable: | | | | | | | | |
| Customers | | | 34,434 | | | | 46,657 | |
| Affiliated Companies | | | 43,219 | | | | 19,542 | |
| Miscellaneous | | | 17,739 | | | | 9,952 | |
| Allowance for Uncollectible Accounts | | | (588 | ) | | | (64 | ) |
| Total Accounts Receivable | | | 94,804 | | | | 76,087 | |
| Fuel | | | | | | | | |
| (December 31, 2010 amount includes $35,055 related to Sabine) | | | 91,777 | | | | 121,453 | |
| Materials and Supplies | | | 50,395 | | | | 54,484 | |
| Risk Management Assets | | | 1,209 | | | | 3,049 | |
| Deferred Income Tax Benefits | | | 15,529 | | | | 13,820 | |
| Accrued Tax Benefits | | | 37,900 | | | | 16,164 | |
| Regulatory Asset for Under-Recovered Fuel Costs | | | 758 | | | | 1,639 | |
| Prepayments and Other Current Assets | | | 24,270 | | | | 20,503 | |
| TOTAL CURRENT ASSETS | | | 404,378 | | | | 343,743 | |
| | | | | | | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
| Electric: | | | | | | | | |
| Generation | | | 2,297,463 | | | | 1,837,318 | |
| Transmission | | | 943,724 | | | | 870,069 | |
| Distribution | | | 1,611,129 | | | | 1,447,559 | |
| Other Property, Plant and Equipment | | | | | | | | |
| (December 31, 2010 amount includes $224,857 related to Sabine) | | | 632,158 | | | | 733,310 | |
| Construction Work in Progress | | | 1,071,603 | | | | 1,176,639 | |
| Total Property, Plant and Equipment | | | 6,556,077 | | | | 6,064,895 | |
| Accumulated Depreciation and Amortization | | | | | | | | |
| (December 31, 2010 amount includes $91,840 related to Sabine) | | | 2,130,351 | | | | 2,086,333 | |
| TOTAL PROPERTY, PLANT AND EQUIPMENT – NET | | | 4,425,726 | | | | 3,978,562 | |
| | | | | | | | | |
| OTHER NONCURRENT ASSETS | | | | | | | | |
| Regulatory Assets | | | 332,698 | | | | 268,165 | |
| Long-term Risk Management Assets | | | 438 | | | | 84 | |
| Deferred Charges and Other Noncurrent Assets | | | 80,327 | | | | 49,479 | |
| TOTAL OTHER NONCURRENT ASSETS | | | 413,463 | | | | 317,728 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 5,243,567 | | | $ | 4,640,033 | |
| | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
| SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | |
| CONSOLIDATED BALANCE SHEETS | |
| LIABILITIES AND EQUITY | |
| December 31, 2010 and 2009 | |
| | |
| | | 2010 | | | 2009 | |
| | | (in thousands) | |
| CURRENT LIABILITIES | | | | | | |
| Accounts Payable: | | | | | | |
| General | | $ | 162,271 | | | $ | 160,870 | |
| Affiliated Companies | | | 64,474 | | | | 59,818 | |
| Short-term Debt – Nonaffiliated | | | 6,217 | | | | 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 | | | 4,067 | | | | 844 | |
| Customer Deposits | | | 48,245 | | | | 41,269 | |
| Accrued Taxes | | | 30,516 | | | | 24,720 | |
| Accrued Interest | | | 39,856 | | | | 33,179 | |
| Obligations Under Capital Leases | | | 13,265 | | | | 14,617 | |
| Regulatory Liability for Over-Recovered Fuel Costs | | | 16,432 | | | | 13,762 | |
| Provision for SIA Refund | | | 7,698 | | | | 19,307 | |
| Other Current Liabilities | | | 59,420 | | | | 71,781 | |
| TOTAL CURRENT LIABILITIES | | | 493,596 | | | | 501,463 | |
| | | | | | | | | |
| NONCURRENT LIABILITIES | | | | | | | | |
| Long-term Debt – Nonaffiliated | | | 1,728,385 | | | | 1,419,747 | |
| Long-term Risk Management Liabilities | | | 338 | | | | 221 | |
| Deferred Income Taxes | | | 624,333 | | | | 485,936 | |
| Regulatory Liabilities and Deferred Investment Tax Credits | | | 393,673 | | | | 333,935 | |
| Asset Retirement Obligations | | | 56,632 | | | | 60,562 | |
| Employee Benefits and Pension Obligations | | | 96,314 | | | | 125,956 | |
| Obligations Under Capital Leases | | | 115,399 | | | | 134,044 | |
| Deferred Credits and Other Noncurrent Liabilities | | | 62,852 | | | | 49,315 | |
| TOTAL NONCURRENT LIABILITIES | | | 3,077,926 | | | | 2,609,716 | |
| | | | | | | | | |
| TOTAL LIABILITIES | | | 3,571,522 | | | | 3,111,179 | |
| | | | | | | | | |
| Cumulative Preferred Stock Not Subject to Mandatory Redemption | | | 4,696 | | | | 4,697 | |
| | | | | | | | | |
| Rate Matters (Note 4) | | | | | | | | |
| Commitments and Contingencies (Note 6) | | | | | | | | |
| | | | | | | | | |
| 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 | | | 868,840 | | | | 726,478 | |
| Accumulated Other Comprehensive Income (Loss) | | | (12,491 | ) | | | (12,991 | ) |
| TOTAL COMMON SHAREHOLDER’S EQUITY | | | 1,666,988 | | | | 1,524,126 | |
| | | | | | | | | |
| Noncontrolling Interest | | | 361 | | | | 31 | |
| | | | | | | | | |
| TOTAL EQUITY | | | 1,667,349 | | | | 1,524,157 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | | $ | 5,243,567 | | | $ | 4,640,033 | |
| | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
| SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| For the Years Ended December 31, 2010, 2009 and 2008 | |
| (in thousands) | |
| | | | | |
| | | 2010 | | | 2009 | | | 2008 | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net Income | | $ | 146,684 | | | $ | 117,203 | | | $ | 96,445 | |
| Adjustments to Reconcile Net Income to Net Cash Flows from | | | | | | | | | | | | |
| Operating Activities: | | | | | | | | | | | | |
| Depreciation and Amortization | | | 126,901 | | | | 145,144 | | | | 145,011 | |
| Deferred Income Taxes | | | 81,764 | | | | 28,016 | | | | 62,060 | |
| Provision for SIA Refund | | | - | | | | - | | | | 54,100 | |
| Extraordinary Loss, Net of Tax | | | - | | | | 5,325 | | | | - | |
| Allowance for Equity Funds Used During Construction | | | (45,646 | ) | | | (46,737 | ) | | | (14,908 | ) |
| Mark-to-Market of Risk Management Contracts | | | 4,826 | | | | 650 | | | | 5,294 | |
| Pension Contributions to Qualified Plan Trust | | | (29,065 | ) | | | - | | | | - | |
| Fuel Over/Under-Recovery, Net | | | (6,089 | ) | | | 68,024 | | | | (86,864 | ) |
| Change in Regulatory Liabilities | | | 26,671 | | | | (2,310 | ) | | | 598 | |
| Change in Other Noncurrent Assets | | | (15,207 | ) | | | 20,333 | | | | 27,121 | |
| Change in Other Noncurrent Liabilities | | | 21,958 | | | | 9,111 | | | | (8,287 | ) |
| Changes in Certain Components of Working Capital: | | | | | | | | | | | | |
| Accounts Receivable, Net | | | (21,507 | ) | | | 113,134 | | | | (52,375 | ) |
| Fuel, Materials and Supplies | | | 21,498 | | | | (26,190 | ) | | | (25,427 | ) |
| Accounts Payable | | | (23,004 | ) | | | 40,981 | | | | (36,422 | ) |
| Accrued Taxes, Net | | | (18,788 | ) | | | (25,252 | ) | | | 8,015 | |
| Accrued Interest | | | 6,570 | | | | (3,468 | ) | | | 19,612 | |
| Other Current Assets | | | (3,182 | ) | | | 700 | | | | 7,928 | |
| Other Current Liabilities | | | (1,433 | ) | | | (33,844 | ) | | | 22,309 | |
| Net Cash Flows from Operating Activities | | | 272,951 | | | | 410,820 | | | | 224,210 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction Expenditures | | | (420,485 | ) | | | (596,581 | ) | | | (692,162 | ) |
| Change in Advances to Affiliates, Net | | | (34,405 | ) | | | (34,883 | ) | | | - | |
| Equity Investment in Oxbow Lignite Company | | | - | | | | (12,873 | ) | | | - | |
| Acquisition of Red River Mining Company | | | - | | | | (15,650 | ) | | | - | |
| Acquisition of Valley Electric Membership Corporation | | | (101,841 | ) | | | - | | | | - | |
| Proceeds from Sales of Assets | | | 5,356 | | | | 105,999 | | | | 1,107 | |
| Other Investing Activities | | | (1,795 | ) | | | (2,499 | ) | | | (1,290 | ) |
| Net Cash Flows Used for Investing Activities | | | (553,170 | ) | | | (556,487 | ) | | | (692,345 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Capital Contribution from Parent | | | - | | | | 142,500 | | | | 200,000 | |
| Issuance of Long-term Debt – Nonaffiliated | | | 399,394 | | | | - | | | | 437,042 | |
| Credit Facility Borrowings | | | 99,688 | | | | 126,903 | | | | 86,095 | |
| Change in Advances from Affiliates, Net | | | - | | | | (2,526 | ) | | | 961 | |
| Retirement of Long-term Debt – Nonaffiliated | | | (53,500 | ) | | | (4,406 | ) | | | (160,444 | ) |
| Retirement of Long-term Debt – Affiliated | | | (50,000 | ) | | | - | | | | - | |
| Retirement of Cumulative Preferred Stock | | | (1 | ) | | | - | | | | - | |
| Credit Facility Repayments | | | (100,361 | ) | | | (127,185 | ) | | | (79,208 | ) |
| Proceeds from Dragline Sale/Leaseback | | | - | | | | 22,831 | | | | - | |
| Principal Payments for Capital Lease Obligations | | | (12,183 | ) | | | (10,952 | ) | | | (11,511 | ) |
| Dividends Paid on Common Stock – Nonaffiliated | | | (3,763 | ) | | | (3,375 | ) | | | (5,109 | ) |
| Dividends Paid on Cumulative Preferred Stock | | | (229 | ) | | | (229 | ) | | | (229 | ) |
| Other Financing Activities | | | 1,027 | | | | 1,857 | | | | 706 | |
| Net Cash Flows from Financing Activities | | | 280,072 | | | | 145,418 | | | | 468,303 | |
| | | | | | | | | | | | | |
| Net Increase (Decrease) in Cash and Cash Equivalents | | | (147 | ) | | | (249 | ) | | | 168 | |
| Cash and Cash Equivalents at Beginning of Period | | | 1,661 | | | | 1,910 | | | | 1,742 | |
| Cash and Cash Equivalents at End of Period | | $ | 1,514 | | | $ | 1,661 | | | $ | 1,910 | |
| | | | | | | | | | | | | |
| SUPPLEMENTARY INFORMATION | | | | | | | | | | | | |
| Cash Paid for Interest, Net of Capitalized Amounts | | $ | 70,729 | | | $ | 80,671 | | | $ | 47,029 | |
| Net Cash Paid (Received) for Income Taxes | | | 8,350 | | | | 19,615 | | | | (33,275 | ) |
| Noncash Acquisitions Under Capital Leases | | | 1,593 | | | | 51,217 | | | | 25,398 | |
| Construction Expenditures Included in Accounts Payable at December 31, | | | 94,836 | | | | 71,431 | | | | 76,826 | |
| Noncash Assumption of Liabilities Related to Acquisition of Valley | | | | | | | | | | | | |
| Electric Membership Corporation | | | 8,400 | | | | - | | | | - | |
| SIA Refund Included in Accounts Receivable at December 31, | | | - | | | | - | | | | 85,248 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements of Registrant Subsidiaries beginning on page 246. | |
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
The notes to SWEPCo’s consolidated financial statements are combined with the notes to financial statements for other registrant subsidiaries. Listed below are the notes that apply to SWEPCo. The footnotes begin on page 246.
| | Footnote Reference |
| | |
| Organization and Summary of Significant Accounting Policies | Note 1 |
| New Accounting Pronouncements and Extraordinary Item | Note 2 |
| Goodwill and Other Intangible Assets | Note 3 |
| Rate Matters | Note 4 |
| Effects of Regulation | Note 5 |
| Commitments, Guarantees and Contingencies | Note 6 |
| Acquisitions | Note 7 |
| Benefit Plans | Note 8 |
| Business Segments | Note 9 |
| Derivatives and Hedging | Note 10 |
| Fair Value Measurements | Note 11 |
| Income Taxes | Note 12 |
| Leases | Note 13 |
| Financing Activities | Note 14 |
| Related Party Transactions | Note 15 |
| Property, Plant and Equipment | Note 16 |
| Cost Reduction Initiatives | Note 17 |
| Unaudited Quarterly Financial Information | Note 18 |
INDEX OF NOTES TO FINANCIAL STATEMENTS OF REGISTRANT SUBSIDIARIES
| The notes to financial statements that follow are a combined presentation for the Registrant Subsidiaries. The following list indicates the registrants to which the footnotes apply: |
| | | |
| 1. | Organization and Summary of Significant Accounting Policies | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
| 2. | New Accounting Pronouncements and Extraordinary Item | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
| 3. | Goodwill and Other Intangible Assets | SWEPCo |
| 4. | Rate Matters | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
| 5. | Effects of Regulation | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
| 6. | Commitments, Guarantees and Contingencies | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
| 7. | Acquisitions | SWEPCo |
| 8. | Benefit Plans | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
| 9. | Business Segments | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
| 10. | Derivatives and Hedging | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
| 11. | Fair Value Measurements | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
| 12. | Income Taxes | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
| 13. | Leases | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
| 14. | Financing Activities | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
| 15. | Related Party Transactions | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
| 16. | Property, Plant and Equipment | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
| 17. | Cost Reduction Initiatives | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
| 18. | Unaudited Quarterly Financial Information | APCo, CSPCo, I&M, OPCo, PSO, SWEPCo |
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
ORGANIZATION
The principal business conducted by AEP’s Registrant Subsidiaries is the generation, transmission and distribution of electric power. These companies are subject to regulation by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. These companies are subject to further regulation with regard to rates and other matters by state regulatory commissions.
The Registrant Subsidiaries engage in wholesale electricity marketing and risk management activities in the United States. In addition, I&M provides barging services to both affiliated and nonaffiliated companies and SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Rates and Service Regulation
The Registrant Subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the nine state operating territories in which they operate. The FERC also regulates the Registrant Subsidiaries’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires that a nonregulated affiliate can bill an affiliated public utility company no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system.
The FERC regulates wholesale power markets and wholesale power transactions. The Registrant Subsidiaries’ wholesale power transactions are generally market-based. They are cost-based regulated when the Registrant Subsidiaries negotiate and file a cost-based contract with the FERC or the FERC determines that the Registrant Subsidiaries have “market power” in the region where the transaction occurs. The Registrant Subsidiaries have entered into wholesale power supply contracts with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. PSO’s and SWEPCo’s wholesale power transactions in the SPP region are cost-based due to PSO and SWEPCo having market power in the SPP region.
The state regulatory commissions regulate all of the distribution operations and rates of the Registrant Subsidiaries retail public utilities on a cost basis. They also regulate the retail generation/power supply operations and rates except in Ohio. The ESP rates in Ohio continue the process of aligning generation/power supply rates over time with market rates. SWEPCo operates in the SPP area which includes a portion of Texas. In 2009, the Texas legislature amended its restructuring legislation for the generation portion of SWEPCo’s Texas retail jurisdiction to delay indefinitely restructuring requirements. As a result, SWEPCo reapplied accounting guidance for “Regulated Operations” to its Texas generation operations.
The FERC also regulates the Registrant Subsidiaries’ wholesale transmission operations and rates. The FERC claims jurisdiction over retail transmission rates when retail rates are unbundled in connection with restructuring. CSPCo’s and OPCo’s retail transmission rates in Ohio, APCo’s retail transmission rates in Virginia and I&M’s retail transmission rates in Michigan are unbundled. CSPCo’s and OPCo’s retail transmission rates in Ohio and APCo’s retail transmission rates in Virginia are based on the FERC’s Open Access Transmission Tariff (OATT) rates that are cost-based. Although I&M’s retail transmission rates in Michigan are unbundled, retail transmission rates are regulated, on a cost basis, by the Michigan Public Servic e Commission. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions.
In addition, the FERC regulates the SIA, the Interconnection Agreement, the CSW Operating Agreement, the System Transmission Integration Agreement, the Transmission Agreement, the Transmission Coordination Agreement and the AEP System Interim Allowance Agreement, all of which allocate shared system costs and revenues to the Registrant Subsidiaries that are parties to each agreement.
Principles of Consolidation
The consolidated financial statements for APCo and CSPCo include the Registrant Subsidiary and its wholly-owned subsidiaries. The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled variable interest entities (VIEs)). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiaries excluding DHLC (as of January 1, 2010, SWEPCo is no longer the primary beneficiary of DHLC and is no longer required to consolidate DHLC, in accordance with “ASU 2009-17 ‘Consolidations’ ”) and Sabine (a substantially-controlled VIE). The consolidated financial statements for OPCo include the Registrant Subsidiary and JMG (a substantially-controlled VIE th at was dissolved in December 2009). Intercompany items are eliminated in consolidation. The Registrant Subsidiaries use the equity method of accounting for equity investments where they exercise significant influence but do not hold a controlling financial interest. Such investments are recorded as Deferred Charges and Other Noncurrent Assets on the balance sheets; equity earnings are included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. CSPCo, OPCo, PSO and SWEPCo have ownership interests in generating units that are jointly-owned with nonaffiliated companies. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected in the balance sheets. See “Variable Interest Entities” section of Note 15.
Accounting for the Effects of Cost-Based Regulation
As rate-regulated electric public utility companies, the Registrant Subsidiaries’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” the Registrant Subsidiaries record regulatory assets (deferred expenses) and regulatory liabilities (future revenue reductions or refunds) to reflect the economic effects of regulation by matching expenses with their recovery through regulated revenues and income with its passage to customers through the reduction of regulated revenues. Due to the passage of legislation requiring restructuring and a transition to customer choice and market-based rates, CSPCo an d OPCo discontinued the application of “Regulated Operations” accounting treatment for the generation portion of their business. In 2009, the Texas legislature amended its restructuring legislation for the generation portion of SWEPCo’s Texas retail jurisdiction to delay indefinitely restructuring requirements. As a result, SWEPCo reapplied accounting guidance for “Regulated Operations” to its Texas generation operations.
Accounting guidance for “Discontinuation of Rate-Regulated Operations” requires the recognition of an impairment of stranded net regulatory assets and stranded plant costs if they are not recoverable in regulated rates. In addition, an enterprise is required to eliminate from its balance sheet the effects of any actions of regulators that had been recognized as regulatory assets and regulatory liabilities. Such impairments and adjustments are classified as an extraordinary item. Consistent with accounting guidance for “Discontinuation of Rate-Regulated Operations,” SWEPCo recorded an extraordinary reduction in earnings and shareholder’s equity from the reapplication of “Regulated Operations” accounting guidance in 2009.
Use of Estimates
The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estima tes.
Cash and Cash Equivalents
Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.
Other Cash Deposits
Other Cash Deposits include funds held by trustees primarily for environmental construction expenditures.
Inventory
Fossil fuel inventories are generally carried at average cost. Materials and supplies inventories are carried at average cost.
Accounts Receivable
Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities.
Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrant Subsidiaries accrue and recognize, as Accrued Unbilled Revenues, an estimate of the revenues for energy delivered since the last billing.
AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with CSPCo, I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information.
Allowance for Uncollectible Accounts
Generally, AEP Credit records bad debt expense related to receivables purchased from the Registrant Subsidiaries under a sale of receivables agreement. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves .
Concentrations of Credit Risk and Significant Customers
The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their Operating Revenues as of December 31, 2010.
The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provision for credit loss has been made in the accompanying Registrant Subsidiary financial statements.
Emission Allowances
The Registrant Subsidiaries record emission allowances at cost, including the annual SO2 and NOx emission allowance entitlements received at no cost from the Federal EPA. They follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies for all of the Registrant Subsidiaries except CSPCo who reflects allowances in Emission Allowances. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost. Allowances held for speculation are included in Prepayments and Other Current Assets for all the Registrant Subsidiaries except CSPCo, who reflects allowances held for speculation in Emission Allowances. The purchases and sales of allowances are reported in the Operating Activities section of the Statements of Cash Flows. The net margin on sales of emission allowances is included in Electric Generation, Transmission and Distribution Revenues for nonaffiliated
transactions and in Sales to AEP Affiliates Revenues for affiliated transactions because of its integral nature to the production process of energy and the Registrant Subsidiaries’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions.
Property, Plant and Equipment and Equity Investments
Regulated
Electric utility property, plant and equipment for rate-regulated operations are stated at original purchase cost. Additions, major replacements and betterments are added to the plant accounts. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation under the group composite method of depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in the original cost, less salvage, being ch arged to accumulated depreciation. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of salvage received. These rates and the related lives are subject to periodic review. Removal costs are charged to regulatory liabilities. The costs of labor, materials and overhead incurred to operate and maintain plants are included in operating expenses.
Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held for sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” Equity investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value.
The fair value of an asset or investment is the amount at which that asset or investment could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets or investments in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.
Nonregulated
The generation operations of CSPCo and OPCo generally follow the policies of cost-based rate-regulated operations listed above but with the following exceptions. Property, plant and equipment are stated at fair value at acquisition (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. For nonregulated operations, including generating assets in Ohio, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.” The Registrant Subsidiaries record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense.
Valuation of Nonderivative Financial Instruments
The book values of Cash and Cash Equivalents, Other Cash Deposits, Accounts Receivable, Short-term Debt and Accounts Payable approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability for I&M approximates the best estimate of its fair value.
Fair Value Measurements of Assets and Liabilities
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 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 to estimate the fair value of the underlying investments held in the benefit plan and 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 plans.
Assets in the benefits and 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 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. Observa ble 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. Benefit plan assets included in Level 3 are real estate and private equity investments that are valued using methods requiring judgment including appraisals.
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 | | | | |
Deferred Fuel Costs
The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel revenues billed to customers over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel revenues billed to customers) are generally deferred as current regulatory assets. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrant Subsidiaries’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. When a fuel cost disallowance becomes probable, the Registrant Subsidiaries adjust their FAC deferrals and record provisions for estimated refunds to recognize these probable outcomes. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended.
Changes in fuel costs, including purchased power in Indiana and Michigan for I&M, in Texas, Louisiana and Arkansas for SWEPCo, in Oklahoma for PSO and in Virginia and West Virginia (prior to 2009) for APCo are reflected in rates in a timely manner through the FAC. Beginning in 2009, changes in fuel costs, including purchased power in Ohio for CSPCo and OPCo and in West Virginia for APCo are reflected in rates through FAC phase-in plans. All of the profits from off-system sales are given to customers through the FAC in West Virginia for APCo. A portion of profits from off-system sales are shared with customers through the FAC and other rate mechanisms in Oklahoma for PSO, Texas, Louisiana and Arkansas for SWEPCo, Virginia for APCo and in Indiana and Michigan (all areas of Michigan beginning in Dece mber 2010) for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent (prior to 2009 for CSPCo and OPCo in Ohio), changes in fuel costs or sharing of off-system sales impacted earnings.
Revenue Recognition
Regulatory Accounting
The financial statements of the Registrant Subsidiaries reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.
When regulatory assets are probable of recovery through regulated rates, the Registrant Subsidiaries record them as assets on the balance sheet. The Registrant Subsidiaries test for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the Registrant Subsidiaries write off that regulatory asset as a charge against income.
Traditional Electricity Supply and Delivery Activities
The Registrant Subsidiaries recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrant Subsidiaries recognize the revenues in the financial statements upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue.
Most of the power produced at the generation plants of the AEP East companies is sold to PJM, the RTO operating in the east service territory. The AEP East companies purchase power from PJM to supply power to their customers. Generally, these power sales and purchases are reported on a net basis as revenues in the statements of income. However, purchases of power in excess of sales to PJM, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. Other RTOs in which the Registrant Subsidiaries operate do not function in the same manner as PJM. They function as balancing organizations and not as exchanges.
Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s economic substance. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income. All other non-trading derivative purchases are recorded net in revenues.
In general, the Registrant Subsidiaries record expenses upon receipt of purchased electricity and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated, such as in Ohio for CSPCo and OPCo and until April 2009 in Texas for SWEPCo. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains).
Energy Marketing and Risk Management Activities
AEPSC, on behalf of the Registrant Subsidiaries, engages in wholesale electricity, coal, natural gas and emission allowances marketing and risk management activities focused on wholesale markets where the AEP System owns assets and on adjacent markets. These activities include the purchase and sale of energy under forward contracts at fixed and variable prices and the buying and selling of financial energy contracts which include exchange traded futures and options, as well as over-the-counter options and swaps. Certain energy marketing and risk management transactions are with RTOs.
The Registrant Subsidiaries recognize revenues and expenses from wholesale marketing and risk management transactions that are not derivatives upon delivery of the commodity. The Registrant Subsidiaries use MTM accounting for wholesale marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or a normal purchase or sale. The Registrant Subsidiaries include realized gains and losses on wholesale marketing and risk management transactions in revenues on a net basis on their income statements. For CSPCo and OPCo, the unrealized gains and losses on wholesale marketing and risk management transactions that are accounted for using MTM are included in revenues on a net basis on the income statements. For APCo, I&M, PSO and SWEPCo, who are subject to cost-based regulation, the unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities as appropriate.
Certain qualifying wholesale marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). The Registrant Subsidiaries initially record the effective portion of the cash flow hedge’s gain or loss as a component of AOCI. When the forecasted transaction is realized and affects net income, the Registrant Subsidiaries subsequently reclassify the gain or loss on the
hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their income statements. For CSPCo and OPCo, the ineffective portion of the gain or loss is recognized in revenues or expense in the income statements immediately. APCo, I&M, PSO, and SWEPCo, who are subject to cost-based regulation, defer the ineffective portion as regulatory assets (for losses) and regulatory liabilities (for gains). See “Accounting for Cash Flow Hedging Strategies” section of Note 10.
Levelization of Nuclear Refueling Outage Costs
In order to match costs with nuclear refueling cycles, I&M defers incremental operation and maintenance costs associated with periodic refueling outages at its Cook Plant and amortizes the costs over the period beginning with the month following the start of each unit’s refueling outage and lasting until the end of the month in which the same unit’s next scheduled refueling outage begins. I&M adjusts the amortization amount as necessary to ensure full amortization of all deferred costs by the end of the refueling cycle.
Maintenance
The Registrant Subsidiaries expense maintenance costs as incurred. If it becomes probable that the Registrant Subsidiaries will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. PSO defers distribution tree trimming costs above the level included in base rates and amortizes those deferrals commensurate with recovery through a rate rider in Oklahoma. PSO also amortizes deferred ice storm costs commensurate with their recovery through a rate rider.
Income Taxes and Investment Tax Credits
The Registrant Subsidiaries use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence.
When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense.
Investment tax credits are accounted for under the flow-through method except where regulatory commissions have reflected investment tax credits in the rate-making process on a deferral basis. Investment tax credits that have been deferred are amortized over the life of the plant investment.
The Registrant Subsidiaries account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrant Subsidiaries classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation.
Excise Taxes
As agents for some state and local governments, the Registrant Subsidiaries collect from customers certain excise taxes levied by those state or local governments on customers. The Registrant Subsidiaries do not record these taxes as revenue or expense.
Government Grants
In 2010, APCo received final approval for a federal stimulus grant for a commercial scale Carbon Capture and Sequestration facility under consideration at the Mountaineer Plant. Also in 2010, CSPCo received final approval for a federal stimulus grant for the gridSMART® demonstration program. For each project, APCo and CSPCo are reimbursed for allowable costs incurred during the billing period. These reimbursements result in the reduction of Other Operation and Maintenance expenses on the Consolidated Statements of Income or a reduction in Construction Work in Progress on the Consolidated Balance Sheets.
Debt and Preferred Stock
Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Some jurisdictions require that these costs be expensed upon reacquisition. The Registrant Subsidiaries report gains and losses on the reacquisition of debt for operations that are not subject to cost-based rate regulation in Interest Expense.
Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The net amortization expense is included in Interest Expense.
Where reflected in rates, redemption premiums paid to reacquire preferred stock of Registrant Subsidiaries are included in paid-in capital and amortized to retained earnings commensurate with their recovery in rates. The excess of par value over costs of preferred stock reacquired is credited to paid-in capital and reclassified to retained earnings upon the redemption of the entire preferred stock series.
Goodwill and Intangible Assets
SWEPCo is the only Registrant Subsidiary with an intangible asset with a finite life. SWEPCo amortizes the asset over its estimated life to its residual value (see Note 3 – Goodwill and Other Intangible Assets). The Registrant Subsidiaries have no recorded goodwill or intangible assets with indefinite lives as of December 31, 2010 and 2009.
Investments Held in Trust for Future Liabilities
AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and spent nuclear fuel disposal. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the interest rate sensitivity of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocation and periodically rebalance the investments to targeted allocation when appro priate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance.
Benefit Plans
All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan.
The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimizing net returns. Strategies used include:
| · | Maintaining a long-term investment horizon. |
| · | Diversifying assets to help control volatility of returns at acceptable level. |
| · | Managing fees, transaction costs and tax liabilities to maximize investment earnings. |
| · | Using active management of investments where appropriate risk/return opportunities exist. |
| · | Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks. |
| · | Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification. |
The target asset allocation and allocation ranges are as follows:
| Pension Plan Assets | | Minimum | | Target | | Maximum |
| Domestic Equity | | 30.0 | % | | 35.0 | % | | 40.0 | % |
| International and Global Equity | | 10.0 | % | | 15.0 | % | | 20.0 | % |
| Fixed Income | | 35.0 | % | | 39.0 | % | | 45.0 | % |
| Real Estate | | 4.0 | % | | 5.0 | % | | 6.0 | % |
| Other Investments | | 1.0 | % | | 5.0 | % | | 7.0 | % |
| Cash | | 0.5 | % | | 1.0 | % | | 3.0 | % |
| | | | | | | |
| OPEB Plans Assets | | Minimum | | Target | | Maximum |
| Equity | | 61.0 | % | | 66.0 | % | | 71.0 | % |
| Fixed Income | | 29.0 | % | | 32.0 | % | | 37.0 | % |
| Cash | | 1.0 | % | | 2.0 | % | | 4.0 | % |
The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities. Investment policies prohibit the benefit trust funds from purchasing securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law. Each investment manager's portfolio is compared to a diversified benchmark index.
For equity investments, the limits are as follows:
| · | No security in excess of 5% of all equities. |
| · | Cash equivalents must be less than 10% of an investment manager's equity portfolio. |
| · | Individual stock must be less than 10% of each manager's equity portfolio. |
| · | No investment in excess of 5% of an outstanding class of any company. |
| · | No securities may be bought or sold on margin or other use of leverage. |
For fixed income investments, the concentration limits must not exceed:
| · | 20% in non-US dollar denominated |
| · | 5% convertible securities |
| · | 60% for bonds rated AA+ or lower |
| · | 50% for bonds rated A+ or lower |
| · | 10% for bonds rated BBB- or lower |
For obligations of non-government issuers the following limitations apply:
| · | AAA rated debt: a single issuer should account for no more than 5% of the portfolio. |
| · | AA+, AA, AA- rated debt: a single issuer should account for no more than 3% of the portfolio. |
| · | Debt rated A+ or lower: a single issuer should account for no more than 2% of the portfolio. |
| · | No more than 10% of the portfolio may be invested in high yield and emerging market debt combined at any time. |
A portion of the pension assets is invested in real estate funds to provide diversification, add return, and hedge against inflation. Real estate properties are illiquid, difficult to value, and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type, and risk classification. Real estate holdings include core, value-added, and development risk classifications and some investments in Real Estate Investment Trusts (REITs), which are publicly traded real estate securities classified as Level 1.
A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value, and not actively traded. The pension plan uses limited partnerships and commingled funds to invest across the private equity investment spectrum. The private equity holdings are with six general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout, and hybrid debt and equity investment instruments. Commingled private equity funds are used to enhance the holdin gs’ diversity.
AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for cash collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the cash collateral is invested. The difference between the rebate owed to the borrower and the cash collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is providing modest incremental income with a limited increase in risk.
Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees' Beneficiary Association (VEBA) trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities.
Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.
Nuclear Trust Funds
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, I&M or their affiliates. |
| · | Withdrawals permitted only for payment of decommissioning costs and trust expenses. |
I&M maintains trust funds for each regulatory jurisdiction. The trust assets may not be used for another jurisdiction’s liabilities. Regulatory approval is required to withdraw decommissioning funds. 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 these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its Consolidated Balance Sheet. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both debt and 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 securit ies which will affect any future unrealized gain or realized gains or losses 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. Consequently, the changes in fair value of trust assets do not affect earnings or AOCI. See the “Nuclear Contingencies” section of Note 6 for additional discussion of nuclear matters. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts.
Comprehensive Income (Loss)
Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).
Components of Accumulated Other Comprehensive Income (Loss) (AOCI)
AOCI is included on the balance sheets in the equity section. Components of AOCI for the Registrant Subsidiaries as of December 31, 2010 and 2009 is shown in the following table:
| | | December 31, |
| | | 2010 | | 2009 |
| | | (in thousands) |
| Cash Flow Hedges, Net of Tax | | | | | | |
| APCo | | $ | (56) | | $ | (7,193) |
| CSPCo | | | (134) | | | (376) |
| I&M | | | (8,685) | | | (9,896) |
| OPCo | | | 10,583 | | | 11,806 |
| PSO | | | 8,494 | | | (599) |
| SWEPCo | | | (4,190) | | | (4,935) |
| | | | | | | |
| Amortization of Pension and OPEB Deferred Costs, Net of Tax | | | | | | |
| APCo | | $ | 12,412 | | $ | 8,240 |
| CSPCo | | | 5,818 | | | 3,343 |
| I&M | | | 2,140 | | | 1,267 |
| OPCo | | | 16,213 | | | 9,166 |
| SWEPCo | | | 3,602 | | | 2,665 |
| | | | | | | |
| Pension and OPEB Funded Status, Net of Tax | | | | | | |
| APCo | | $ | (60,379) | | $ | (51,301) |
| CSPCo | | | (57,020) | | | (52,960) |
| I&M | | | (14,344) | | | (13,072) |
| OPCo | | | (155,615) | | | (139,430) |
| SWEPCo | | | (11,903) | | | (10,721) |
Earnings Per Share (EPS)
APCo, CSPCo, I&M, OPCo, PSO and SWEPCo are wholly-owned subsidiaries of AEP. Therefore, none are required to report EPS.
CSPCo and OPCo Revised Depreciation Rates
Effective January 1, 2009, CSPCo and OPCo revised book depreciation rates for generating plants consistent with a completed depreciation study. OPCo’s overall higher depreciation rates primarily related to shortened depreciable lives for certain OPCo generating facilities. In comparing 2009 and 2008, the change in depreciation rates resulted in a net increase (decrease) in depreciation expense of:
| | | Depreciation |
| | | Expense Variance |
| | | Years Ended |
| | | December 31, |
| | | 2009/2008 |
| | | (in thousands) |
| CSPCo | | $ | (17,815) |
| OPCo | | | 71,056 |
Adjustments to Sale of Receivables Disclosure
In the “Sale of Receivables – AEP Credit” section of Note 14, 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 shareholders’ equity, financial position or cash flows.
Adjustments to Benefit Plans Footnote
In Note 8 – Benefit Plans, the disclosure was expanded to reflect disclosure requirements for each of the individual Registrant Subsidiaries based on their participation in the AEP System. 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 ITEM
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 Registrant Subsidiaries’ financial statements.
Pronouncements Adopted in 2010
The following standard was effective during 2010. Consequently, the financial statements reflect 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. GOODWILL AND OTHER INTANGIBLE ASSETS
Goodwill
There is no goodwill carried by any of the Registrant Subsidiaries.
Other Intangible Assets
SWEPCo’s acquired intangible asset subject to amortization was $7.7 million at December 31, 2009, net of accumulated amortization and was included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s Consolidated Balance Sheet. The amortization life, gross carrying amount and accumulated amortization are:
| | | | December 31, |
| | | | 2010 | | 2009 |
| | | | Gross | | | | Gross | | |
| | Amortization | | Carrying | | Accumulated | | Carrying | | Accumulated |
| | Life | | Amount | | Amortization | | Amount | | Amortization |
| | (in years) | | (in millions) |
| Advanced Royalties | 15 | | $ | - | | $ | - | | $ | 29.4 | | $ | 21.7 |
Amortization of the intangible asset was $1 million and $1 million for 2009 and 2008, respectively.
The Advanced Royalties asset class relates to the lignite mine of DHLC, a wholly-owned subsidiary of SWEPCo. As of January 1, 2010, SWEPCo no longer consolidates DHLC, but rather it is reported as an equity investment resulting in the elimination of a review of this asset by SWEPCo. Also, see “ASU 2009-17 ‘Consolidations’” section of Note 2 for discussion of impact of new accounting guidance effective January 1, 2010.
Starting in 2010, the Registrant Subsidiaries have no intangible assets.
4. RATE MATTERS
The Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrant Subsidiaries recent significant rate orders and pending rate filings are addressed in this note.
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 limited 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 provided a FAC for the three-year period of the ESP. The FAC was phased in to avoid having the resultant rate increases exceed the ordered annual caps described above. The FAC is subject to quarterly true-ups, annual accounting audits and prudency reviews. See the “2009 Fuel Adjustment Clause Audit” section below. The order allowed CSPCo and OPCo to defer any unrecovered FAC costs resulting from the annual caps and accrued 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 associated with the Ormet i nterim 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 deferral as of December 31, 2010 was $476 million for OPCo excluding $30 million 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 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 gridSMART® 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 the Supreme Court of Ohio is pending.
In April 2010, the Industrial Energy Users-Ohio 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.
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 under the Significantly Excessive Earnings Test (SEET). If the rate adjustments, in the aggregate, result in significantly excessive earnings, the excess amount could be returned to customers. In September 2010, CSPCo and OPCo filed their 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. In January 2011, the PUCO issued an order that determined a return on common equity for 2009 in excess of 17.6% would be significantly excessive. The PUCO determined that OPCo’s 2009 earnings were not significantly ex cessive but determined relevant CSPCo earnings, excluding off-system sales margins, to be 19.73%, which 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 date of the order, with any remaining balance to be credited to CSPCo’s customers on a per kilowatt basis which began with the first billing cycle in February 2011 through December 2011. Several parties, including CSPCo and OPCo, have filed requests for rehearing with the PUCO, which remain pending. CSPCo and OPCo are required to file their 2010 SEET filing with the PUCO in 2011. Based upon the approach in the PUCO 2009 order, management does not currently believe that there are significantly excessive 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.
Proposed 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 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 individually vary, but on average, customers will experience net base generation increases of 1.4% in 2012 and 2.7% for the period January 2013 through May 2014.
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.
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 is estimated to be $59 million, as well as future closure costs incurred after December 2010. OPCo also requested 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 they are incurred. Also in Octo ber 2010, OPCo filed a retirement notification with PJM pending PUCO approval of OPCo’s application to close Sporn Unit 5, which was granted by PJM. Pending PUCO approval, Sporn Unit 5 continues to operate. 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 their confidential audit report 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 reduced fuel expense in 2009 and 2010. Hearings were held in August 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 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. The approval of the FAC, 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. The Industrial Energy Users-Ohio, CSPCo and OPCo filed Notices of Appeal regarding aspects of this decision with the Supreme Court of Ohio. A hearing at the Supreme Court of Ohio was held in February 2011. Through Sept ember 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 recognized carrying charges. 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 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. 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-Ohio 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-Ohio 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.
In June 2010, Industrial Energy Users-Ohio filed a notice of appeal of the 2010 PUCO-approved EDR with the Supreme Court of Ohio. The Industrial Energy Users-Ohio raised the same issues as noted in the 2009 EDR appeal plus 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.
As of December 31, 2010, CSPCo and OPCo have incurred $38 million and $30 million, respectively, in EDR costs including carrying costs. Of these costs, CSPCo and OPCo have collected $35 million and $26 million, respectively, through the EDR, which CSPCo and OPCo began collecting in January 2010. The remaining $3 million and $4 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.
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 since this rider is subject to the rate increase caps authorized by the PUCO in the ESP proceedings, but will increase the ESP phase-in plan deferrals associated with the FAC.
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 December 31, 2010, 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, all pre-construction costs that may be utilized in projects at other sites must be refunded to Ohio ratepayers with interest. 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 $125 million for transmission, excluding AFUDC. SWEPCo’s share is currently estimated to cost $1.3 billion, excluding AFUDC, plus the additional $125 million for transmission, excluding AFUDC. As of December 31, 2010, excluding costs attributable to its joint owners, SWEPCo has capitalized approxim ately $1 billion of expenditures (including AFUDC and capitalized interest of $137 million and related transmission costs of $66 million). As of December 31, 2010, the joint owners and SWEPCo have contractual construction commitments of approximately $321 million (including related transmission costs of $3 million). SWEPCo’s share of the contractual construction commitments is $235 million. If the plant is cancelled, the joint owners and SWEPCo would incur contractual construction cancellation fees, based on construction status as of December 31, 2010, of approximately $121 million (including related transmission cancellation fees of $1 million). SWEPCo’s share of the contractual construction cancellation fees would be approximately $89 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. 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 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.
The LPSC approved SWEPCo’s application to construct the Turk Plant. The Sierra Club filed a complaint with the LPSC to begin an investigation into the construction of the Turk Plant. In November 2010, the LPSC dismissed 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. The 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 asked the Arkansas Court of Appeals to overturn the Circuit Court’s December 2010 decision. A decision from the Arkansas Court of Appeals is pending.
A wetlands permit was issued by the U.S. Army Corps of Engineers in December 2009. In 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, 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 constru ct the Turk Plant without obtaining a certificate from the APSC. In 2010, the motions for preliminary injunction were partially granted and upheld on appeal pending a hearing. 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. A hearing on SWEPCo’s appeal is scheduled for March 2011. 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 accepted the request.
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 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. The Arkansas Court of Appeals issued a decision in July 2010 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. In January 2011, the appella nts filed requests to withdraw their appeals at the Court of Appeals and the APSC postponed a scheduled hearing pending a ruling on those requests. In February 2011, the Court of Appeals dismissed the appeals, and the APSC subsequently closed the remand docket, finding the CECPN decisions final and non-appealable. As previously discussed, the preliminary injunction issued by the Federal District Court related to the wetlands permit also impacts the uncompleted construction on portions of the transmission lines.
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 December 31, 2010, the Stall Unit cost applicable to the cap was $426 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 r eceived CWIP treatment for a portion of the Stall Unit in the 2009 Texas Base Rate Filing. See “2009 Texas Base Rate Filing” section below. The Stall Unit will be phased into Louisiana rates 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. 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 condition.
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 constructio n of the Stall Unit and $10 million in other increases. In addition, the settlement agreement decreased annual depreciation expense by $17 million and allowed 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 purchased 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. The testimony included 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 under a ten-year gas transportation agreement that began in 2009 for the Mattison Plant located in northwest Arkansas. In January 2011, the PUCT issued an order which overturned a portion of the PFD that recommended a finding of imprudence on the Mattison gas contract. The impact of this order had an immaterial impact on SWEPCo’s financial statements.
Louisiana 2008 Formula Rate Filing
In April 2008, SWEPCo filed its first formula rate filing under an approved three-year formula rate plan (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. A settlement stipulation was reached by the parties and is pending LPSC approval. SWEPCo began refunding customers in August 2010.
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, consultants for the LPSC objected to certain components of SWEPCo’s FRP calculation. In February 2011, a settlement stipulation was reached by the parties and is pending LPSC approval. The settlement stipulation agreed to a $2 million refund, which was recorded in 2010 as a provision in Other Current Liabilities on SWEPCo's Consolidated Balance Sheets. If a refund is required, it could reduce future net income and cash flows.
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. 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.
APCo Rate Matters
2009 Virginia Base Rate Case
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 common equity. The order denied recovery of the Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility, which resulted in a pretax write-off of $54 million in Other Operation. See “Mountaineer Carbon Capture and Storage Project” section below. In addition, the order allowed the deferral of approximately $25 million of incremental storm expense incurred in 2009. Approximately $3 million, including interest, was refunded to customers in September 2010 related to the collection of interim rates.
2010 West Virginia Base Rate Case
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. The filing also included a request for recovery of and a return on the West Virginia jurisdictional share of the Mountaineer Carbon Capture and Storage Product Validation Facility. In December 2010, a settlement agreement was filed with the WVPSC to increase annual base rates by $54 million, effective March 2011. In addition, the settlement agreement allows APCo to defer and amortize up to $18 million of previously expensed 2009 incremental storm expenses over a period of eight years. A decision from the WVPSC is expected in March 2011.
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. As of December 31, 2010, APCo has recorded a noncurrent regulatory asset of $60 million related to the PVF.
In APCo’s July 2009 Virginia base rate filing, APCo requested recovery of and a return on its 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 PVF costs. See “2009 Virginia Base Rate Case” section above.
In APCo’s May 2010 West Virginia base rate filing, APCo requested recovery of and a return on its West Virginia jurisdictional share of its project costs and recovery of the related asset retirement obligation regulatory asset amortization and accretion. In December 2010, a settlement agreement was filed with the WVPSC to increase annual base rates by $54 million, effective March 2011. A decision from the WVPSC is expected in March 2011. If APCo cannot recover its remaining investment in and expenses related to the PVF, it would reduce future net income and cash flows and impact financial condition.
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 carbon capture and sequestration (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 December 31, 2010, APCo has incurred $14 million in
total costs and has received $5 million of DOE funding resulting in a net $9 million balance included in Construction Work In Progress on the Consolidated Balance Sheets. If APCo is unable to recover the costs of the CCS project, it would reduce future net income and cash flows.
APCo’s Filings for an IGCC Plant
In 2008, the Virginia SCC issued 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 order was based upon the Virginia SCC'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 sequestration facilities. During 2009, based on the order received in Virginia, the WVPSC removed the IGCC case as an active case from its docket and indicated that the conditional CPCN granted in 2008 must be reconsidered if and when APCo proceeds with the IGCC plant.
Through December 31, 2010, 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 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 West Virginia. If the plant is cancelled, APCo plans to seek recovery of its prudently incurred deferred pre-construction costs which, if not recoverable, 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.
In June 2010, the WVPSC approved a settlement agreement for $86 million, including $9 million of construction surcharges 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 weighted average cost of capital carrying costs on the excess under-recovery balance due to the ENEC phase-in as adjusted for the impacts of Accumulated Deferred Income Taxes. As of December 31, 2010, APCo’s ENEC under-recovery balance was $361 million, excluding $3 million of unrecognized equity carrying costs, which is included in noncurrent regulatory assets. The new rates became effective in July 2010.
WPCo Merger with APCo
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.
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) contended that PSO should not have collected the $42 million without specific OCC approval. In December 2010, the OCC issued orders which approved PSO’s 2006 and prior fuel and purchased power costs without any adjustments.
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 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 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 AEPEP was filed. The testimony included unquantified refund recommendations relating to re-pricing of contract transactions. Hearings are currently scheduled for March 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 appealed various issues but 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 included a $24 million increase in depreciation and an 11.5% return on common equity. In January 2011, the OCC approved a settlement agreement which did not change annual revenue or depreciation rates, but transferred $30 million into base rates that was previously being recovered through a capital investment rider. The order provided a 10.15% return on common equity and new rates were effective in Feb ruary 2011.
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 6, Cook Plant 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. In January 2011, a settlement agreement was filed with the IURC. The settlement stated (a) that I&M will credit an additional $14 million to customers through the fuel adjustment clause, (b) that the parties to the settlement will not oppose the need to replace the existing low-pressure turbine at Cook Unit 1, and (c) that the parties to the settlement agree that the cost of the replacement should not be offset by the a ccidental outage insurance proceeds received by I&M. In February 2011, the IURC approved the settlement agreement as filed.
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 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 that I&M is entitled to retain the accidental outage insurance proceeds since it made customers whole regarding the replacement power costs. In October 2010, a settlement agreement was filed with the MPSC which included deferring the Unit 1 outage issue to the 2010 PSCR reconciliation, which will be filed in March 2011. 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 6.
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 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 requirement includes the amortization of $6 million in previously expensed restructuring costs over five years, which I&M deferred in October 2010 and began amortizing in December 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. Through December 2010, I&M recorded a provision for refund of $3 million, including interest, related to interim rates that were in effect through November 2010. In January 2011, I&M filed an application with the MPSC requesting the MPSC find that $3 million, including interest, is the total amount to be refunded to customers. I&M is proposing to refund this amount to customers during April 2011. A decisio n from the MPSC is pending.
FERC Rate Matters
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. APCo’s, CSPCo’s, I&M’s and OPCo’s portions of recognized gross SECA revenues are as follows:
| Company | | (in millions) |
| APCo | | $ | 70.2 |
| CSPCo | | | 38.8 |
| I&M | | | 41.3 |
| OPCo | | | 53.3 |
In 2006, a FERC Administrative Law Judge (ALJ) issued an initial decision finding 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 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.
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 December 31, 2010 was $32 million. APCo’s, CSPCo’s, I&M’s and OPCo’s reserve balances at December 31, 2010 were:
| Company | | December 31, 2010 |
| | | (in millions) |
| APCo | | $ | 10.0 |
| CSPCo | | | 5.6 |
| I&M | | | 5.9 |
| OPCo | | | 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 $10 million including estimated interest of $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 to be Received |
| | | (in millions) |
| APCo | | $ | 6.4 | | $ | 3.2 |
| CSPCo | | | 3.5 | | | 1.8 |
| I&M | | | 3.7 | | | 1.9 |
| OPCo | | | 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 PSO and SWEPCo
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.
In 2009, AEP made a compliance filing with the FERC and the AEP East companies refunded approximately $250 million to the AEP West companies. Following authorized regulatory treatment, the AEP West companies shared a portion of SIA margins with their customers during the period June 2000 to March 2006. In 2008, the AEP West companies recorded a provision for refund reflecting the sharing. Refunds have been or 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
The AEP East companies 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 generally 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. In October 2010, the FERC approved a settlement agreement for the new TA effective November 1, 2010. The impacts of t he settlement agreement will be phased-in for retail rate making purposes in certain jurisdictions over periods of up to four years.
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.
In October 2010, a settlement agreement was approved by the FERC which resulted 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. Prior to November 2010, the remaining $44 million was billed to the AEP East companies and was generally offset by compensation from PJM for use of the AEP East companies’ transmission facilities so that net income was not directly affected. Beginning in November 2010, AEP East companies, KGPCo and WPCo, which are parties to the modified TA, allocate revenue and expenses on different methodologies and will affect net income. See “Modification of the Transmission Agreement” above.
The 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.
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 dated back to the start of the MISO market in 2005. In January 2011, PJM and 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.
5. EFFECTS OF REGULATION
Regulatory assets and liabilities are comprised of the following items:
| | | | | | | | APCo | | I&M |
| | | | | | | | | | Remaining | | | | Remaining |
| | | | | | | | December 31, | | Recovery | | December 31, | | Recovery |
| Regulatory Assets: | | 2010 | | 2009 | | Period | | 2010 | | 2009 | | Period |
| | | (in thousands) | | | | (in thousands) | | |
| Current Regulatory Assets | | | | | | | | | | | | | | | | |
| Under-recovered Fuel Costs - earns a return | | $ | 18,300 | | $ | 78,685 | | 1 year | | $ | - | | $ | 4,826 | | |
| Under-recovered Fuel Costs - does not earn a return | | | - | | | - | | | | | 8,467 | | | - | | 1 year |
| Total Current Regulatory Assets | | $ | 18,300 | | $ | 78,685 | | | | $ | 8,467 | | $ | 4,826 | | |
| | | | | | | | | | | | | | | | | |
| Noncurrent Regulatory Assets | | | | | | | | | | | | | | | | |
| 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 | | $ | - | | $ | - | | | | $ | - | (b) | $ | 6,311 | | |
| | Regulatory Assets Currently Not Earning a Return | | | | | | | | | | | | | | | | |
| | | | Mountaineer Carbon Capture and Storage | | | | | | | | | | | | | | | | |
| | | | | Product Validation Facility | | | 59,866 | | | 110,665 | | | | | - | | | - | | |
| | | | Virginia Environmental Rate Adjustment Clause | | | 55,724 | | | 25,311 | | | | | - | | | - | | |
| | | | Deferred Wind Power Costs | | | 28,584 | | | 5,372 | | | | | - | | | - | | |
| | | | Storm Related Costs | | | 25,225 | | | - | | | | | - | | | - | | |
| | | | Special Rate Mechanism for Century Aluminum | | | 12,628 | | | 12,422 | | | | | - | | | - | | |
| | | | Virginia Transmission Rate Adjustment Clause | | | - | (a) | | 26,184 | | | | | - | | | - | | |
| | | | Deferred PJM Fees | | | - | | | - | | | | | - | (b) | | 6,254 | | |
| | | | Other Regulatory Assets Not Yet Being Recovered | | | 604 | | | 315 | | | | | - | | | - | | |
| Total Regulatory Assets Not Yet Being Recovered | | | 182,631 | | | 180,269 | | | | | - | | | 12,565 | | |
| | | | | | | | | | | | | | | | | |
| Regulatory assets being recovered: | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | Regulatory Assets Currently Earning a Return | | | | | | | | | | | | | | | | |
| | | | Expanded Net Energy Charge | | | 361,314 | (c) | | - | | 3 years | | | - | | | - | | |
| | | | Unamortized Loss on Reacquired Debt | | | 12,679 | | | 13,456 | | 26 years | | | 18,507 | | | 16,326 | | 22 years |
| | | | RTO Formation/Integration Costs | | | 5,952 | | | 6,647 | | 9 years | | | 4,437 | | | 4,967 | | 9 years |
| | | | Customer Choice Implementation Costs | | | - | | | - | | | | | 6,767 | (b) | | - | | 3 years |
| | | | Other Regulatory Assets Being Recovered | | | - | | | - | | | | | 1,103 | | | 1,674 | | various |
| | Regulatory Assets Currently Not Earning a Return | | | | | | | | | | | | | | | | |
| | | | Income Taxes, Net | | | 523,009 | | | 490,356 | | 29 years | | | 159,453 | | | 152,722 | | 37 years |
| | | | Pension and OPEB Funded Status | | | 335,105 | | | 331,631 | | 13 years | | | 268,080 | | | 252,011 | | 13 years |
| | | | Postemployment Benefits | | | 25,484 | | | 26,045 | | 4 years | | | 8,968 | | | 8,398 | | 4 years |
| | | | Virginia Transmission Rate Adjustment Clause | | | 19,271 | (a) | | - | | 2 years | | | - | | | - | | |
| | | | Asset Retirement Obligation | | | 12,560 | | | 14,595 | | 7 years | | | 2,700 | | | 2,120 | | 10 years |
| | | | Virginia Environmental and Reliability Costs | | | | | | | | | | | | | | | | |
| | | | | Recovery | | | 4,421 | | | 76,057 | | 3 years | | | - | | | - | | |
| | | | West Virginia Reliability Expense | | | 3,158 | | | 7,956 | | 1 year | | | - | | | - | | |
| | | | Postretirement Benefits | | | 26 | | | 38 | | 3 years | | | 1,857 | | | 3,373 | | 2 years |
| | | | Cook Nuclear Plant Refueling Outage Levelization | | | - | | | - | | | | | 53,795 | | | 21,856 | | 3 years |
| | | | Off-system Sales Margin Sharing | | | - | | | - | | | | | 13,091 | | | 17,583 | | 1 year |
| | | | Deferred PJM Fees | | | - | | | - | | | | | 7,078 | (b) | | - | | 2 years |
| | | | Deferred Severance Costs | | | - | | | - | | | | | 6,217 | | | - | | 5 years |
| | | | Expanded Net Energy Charge | | | - | (c) | | 281,818 | | | | | - | | | - | | |
| | | | Virginia Restructuring Transition Costs | | | - | | | 4,245 | | | | | - | | | - | | |
| | | | Other Regulatory Assets Being Recovered | | | 1,015 | | | 678 | | various | | | 4,201 | | | 2,869 | | various |
| Total Regulatory Assets Being Recovered | | | 1,303,994 | | | 1,253,522 | | | | | 556,254 | | | 483,899 | | |
| | | | | | | | | | | | | | | | | |
| Total Noncurrent Regulatory Assets | | $ | 1,486,625 | | $ | 1,433,791 | | | | $ | 556,254 | | $ | 496,464 | | |
| | | | | | | | | | | | | | | | | |
| (a) Recovery of regulatory asset through the transmission rate adjustment clause. |
| (b) Recovery of regulatory asset was granted during 2010. |
| (c) The majority of the balance results from the ENEC phase-in plan and earns a weighted average cost of capital carrying charge. |
| | | | | | | | APCo | | I&M |
| | | | | | | | | | Remaining | | | | Remaining |
| | | | | | | | December 31, | | Refund | | December 31, | | Refund |
| Regulatory Liabilities: | | 2010 | | 2009 | | Period | | 2010 | | 2009 | | Period |
| | | (in thousands) | | | | (in thousands) | | |
| Current Regulatory Liability | | | | | | | | | | | | | | | | |
| Over-recovered Fuel Costs - pays a return | | $ | - | | $ | - | | | | $ | 1 | | $ | - | | 1 year |
| Over-recovered Fuel Costs - does not pay a return | | | - | | | - | | | | | - | | | 8,949 | | |
| Total Current Regulatory Liability | | $ | - | | $ | - | | | | $ | 1 | | $ | 8,949 | | |
| | | | | | | | | | | | | | | | | |
| Noncurrent Regulatory Liabilities and | | | | | | | | | | | | | | | | |
| Deferred Investment Tax Credits | | | | | | | | | | | | | | | | |
| Regulatory liabilities not yet being paid: | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| | Regulatory Liabilities Currently Not Paying a Return | | | | | | | | | | | | | | | | |
| | | | Other Regulatory Liabilities Not Yet Being Paid | | $ | - | | $ | - | | | | $ | 147 | | $ | 158 | | |
| Total Regulatory Liabilities Not Yet Being Paid | | | - | | | - | | | | | 147 | | | 158 | | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Regulatory liabilities being paid: | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | Regulatory Liabilities Currently Paying a Return | | | | | | | | | | | | | | | | |
| | | | Asset Removal Costs | | | 500,667 | | | 451,170 | | (a) | | | 357,493 | | | 327,593 | | (a) |
| | | | Deferred Investment Tax Credits | | | 5,097 | | | 8,997 | | 10 years | | | - | | | - | | |
| | Regulatory Liabilities Currently Not Paying a Return | | | | | | | | | | | | | | | | |
| | | | Deferred State Income Tax Coal Credits | | | 28,900 | | | 27,842 | | 9 years | | | - | | | - | | |
| | | | Deferred Investment Tax Credits | | | 1,918 | | | 1,985 | | 10 years | | | 55,416 | | | 57,732 | | 76 years |
| | | | Unrealized Gain on Forward Commitments | | | 25,799 | | | 36,552 | | 5 years | | | 28,045 | | | 27,359 | | 5 years |
| | | | Excess Asset Retirement Obligations for Nuclear | | | | | | | | | | | | | | | | |
| | | | | Decommissioning Liability | | | - | | | - | | | | | 353,689 | | | 280,705 | | (b) |
| | | | Spent Nuclear Fuel Liability | | | - | | | - | | | | | 41,932 | | | 41,517 | | (b) |
| | | | Over-recovery of PJM Expenses | | | - | | | - | | | | | 11,671 | | | 17,827 | | 1 year |
| | | | Indiana Clean Coal Technology Rider Liability | | | - | | | - | | | | | 2,494 | | | 2,416 | | 1 year |
| | | | Other Regulatory Liabilities Being Paid | | | - | | | - | | | | | 1,310 | | | 1,538 | | various |
| Total Regulatory Liabilities Being Paid | | | 562,381 | | | 526,546 | | | | | 852,050 | | | 756,687 | | |
| | | | | | | | | | | | | | | | | |
| Total Noncurrent Regulatory Liabilities and | | | | | | | | | | | | | | | | |
| | Deferred Investment Tax Credits | | $ | 562,381 | | $ | 526,546 | | | | $ | 852,197 | | $ | 756,845 | | |
| | | | | | | | | | | | | | | | | |
| (a) | | Relieved as removal costs are incurred. |
| (b) | | Relieved when plant is decommissioned. |
| | | | | | | | CSPCo | | OPCo |
| | | | | | | | | | Remaining | | | | Remaining |
| | | | | | | | December 31, | | Recovery | | December 31, | | Recovery |
| | | | | | | | 2010 | | 2009 | | Period | | 2010 | | 2009 | | Period |
| Regulatory Assets: | | (in thousands) | | | | (in thousands) | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Noncurrent Regulatory Assets | | | | | | | | | | | | | | | | |
| 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 | | $ | 33,709 | | $ | 26,590 | | | | $ | 21,246 | | $ | 16,278 | | |
| | | | Customer Choice Deferrals | | | 29,716 | | | 28,781 | | | | | 29,141 | | | 28,330 | | |
| | | | Storm Related Costs | | | 19,122 | | | 17,014 | | | | | 11,021 | | | 9,794 | | |
| | | | Acquisition of Monongahela Power | | | 7,929 | | | 10,282 | | | | | - | | | - | | |
| | | | Economic Development Rider | | | 3,057 | | | - | | | | | 3,057 | | | - | | |
| | | | Other Regulatory Assets Not Yet Being Recovered | | | 287 | | | 1,421 | | | | | 391 | | | 1,058 | | |
| | Regulatory Assets Currently Not Earning a Return | | | | | | | | | | | | | | | | |
| | | | Acquisition of Monongahela Power | | | 4,052 | | | - | | | | | - | | | - | | |
| | | | Energy Efficiency/Peak Demand Reduction | | | - | (a) | | 4,071 | | | | | - | | | 4,007 | | |
| | | | Other Regulatory Assets Not Yet Being Recovered | | | 43 | | | 17 | | | | | 58 | | | 22 | | |
| Total Regulatory Assets Not Yet Being Recovered | | | 97,915 | | | 88,176 | | | | | 64,914 | | | 59,489 | | |
| | | | | | | | | | | | | | | | | |
| Regulatory assets being recovered: | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | Regulatory Assets Currently Earning a Return | | | | | | | | | | | | | | | | |
| | | | Unamortized Loss on Reacquired Debt | | | 8,613 | | | 9,357 | | 14 years | | | 7,276 | | | 7,871 | | 28 years |
| | | | RTO Formation/Integration Costs | | | 2,420 | | | 2,692 | | 9 years | | | 6,547 | | | 7,302 | | 9 years |
| | | | Economic Development Rider | | | 710 | | | 10,209 | | 1 year | | | 696 | | | 1,633 | | 1 year |
| | | | Acquisition of Monongahela Power | | | 504 | | | 2,861 | | 1 year | | | - | | | - | | |
| | | | Fuel Adjustment Clause | | | - | | | 36,982 | | | | | 475,835 | | | 303,550 | | 2 to 8 years |
| | | | Other Regulatory Assets Being Recovered | | | 383 | | | - | | various | | | - | | | - | | |
| | Regulatory Assets Currently Not Earning a Return | | | | | | | | | | | | | | | | |
| | | | Pension and OPEB Funded Status | | | 173,755 | | | 175,024 | | 13 years | | | 190,076 | | | 188,149 | | 13 years |
| | | | Income Taxes, Net | | | 3,100 | | | 10,631 | | 25 years | | | 179,186 | | | 168,849 | | 19 years |
| | | | Enhanced Service Reliability Plan | | | 2,990 | | | 2,061 | | 2 years | | | 387 | | | - | | 2 years |
| | | | Postemployment Benefits | | | 2,909 | | | 3,036 | | 4 years | | | 5,897 | | | 6,062 | | 4 years |
| | | | Unrealized Loss on Forward Commitments | | | 2,591 | | | - | | 1 year | | | 3,197 | | | - | | 1 year |
| | | | Energy Efficiency/Peak Demand Reduction | | | 2,221 | (a) | | - | | 2 years | | | - | | | - | | |
| Total Regulatory Assets Being Recovered | | | 200,196 | | | 252,853 | | | | | 869,097 | | | 683,416 | | |
| | | | | | | | | | | | | | | | | |
| Total Noncurrent Regulatory Assets | | $ | 298,111 | | $ | 341,029 | | | | $ | 934,011 | | $ | 742,905 | | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| (a) | | Recovery of regulatory asset was granted during 2010. |
| | | | | | | | CSPCo | | OPCo |
| | | | | | | | | | Remaining | | | | Remaining |
| | | | | | | | December 31, | | Refund | | December 31, | | Refund |
| | | 2010 | | 2009 | | Period | | 2010 | | 2009 | | Period |
| Regulatory Liabilities: | | (in thousands) | | | | (in thousands) | | |
| | | | | | | | | | | | | | | | | |
| Noncurrent Regulatory Liabilities and | | | | | | | | | | | | | | | | |
| Deferred Investment Tax Credits | | | | | | | | | | | | | | | | |
| Regulatory liabilities not yet being paid: | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| | Regulatory Liabilities Currently Not Paying a Return | | | | | | | | | | | | | | | | |
| | | | Over-recovery of Costs Related to gridSMART® | | $ | 6,182 | | $ | 7,477 | | | | $ | - | | $ | - | | |
| | | | Low Income Customers/Economic Recovery | | | 2,260 | | | 2,351 | | | | | 1,160 | | | 1,110 | | |
| | | | Other Regulatory Liabilities Not Yet Being Paid | | | 1,817 | | | 1,823 | | | | | 1,349 | | | 2,476 | | |
| Total Regulatory Liabilities Not Yet Being Paid | | | 10,259 | | | 11,651 | | | | | 2,509 | | | 3,586 | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Regulatory liabilities being paid: | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | Regulatory Liabilities Currently Paying a Return | | | | | | | | | | | | | | | | |
| | | | Asset Removal Costs | | | 137,720 | | | 130,999 | | (a) | | | 118,826 | | | 112,453 | | (a) |
| | | | Transmission Cost Recovery Rider | | | 786 | | | 14,811 | | 1 year | | | 1,633 | | | 10,003 | | 1 year |
| | | | Deferred Investment Tax Credits | | | - | | | - | | | | | 1,085 | | | 1,967 | | 9 years |
| | | | Other Regulatory Liabilities Being Paid | | | 336 | | | 377 | | various | | | - | | | 178 | | |
| | Regulatory Liabilities Currently Not Paying a Return | | | | | | | | | | | | | | | | |
| | | | Deferred Investment Tax Credits | | | 14,787 | | | 16,833 | | 14 years | | | - | | | - | | |
| | | | Energy Efficiency/Peak Demand Reduction | | | - | | | - | | | | | 2,245 | | | - | | 2 years |
| | | | Unrealized Gain on Forward Commitments | | | - | | | - | | | | | 105 | | | - | | 1 year |
| Total Regulatory Liabilities Being Paid | | | 153,629 | | | 163,020 | | | | | 123,894 | | | 124,601 | | |
| | | | | | | | | | | | | | | | | |
| Total Noncurrent Regulatory Liabilities and | | | | | | | | | | | | | | | | |
| | Deferred Investment Tax Credits | | $ | 163,888 | | $ | 174,671 | | | | $ | 126,403 | | $ | 128,187 | | |
| | | | | | | | | | | | | | | | | |
| (a) | | Relieved as removal costs are incurred. |
| | | | | | | | PSO | | SWEPCo |
| | | | | | | | | | Remaining | | | | Remaining |
| | | | | | | | December 31, | | Recovery | | December 31, | | Recovery |
| | | | | | | | 2010 | | 2009 | | Period | | 2010 | | 2009 | | Period |
| Regulatory Assets: | | (in thousands) | | | | (in thousands) | | |
| | | | | | | | | | | | | | | | | |
| Current Regulatory Asset | | | | | | | | | | | | | | | | |
| Under-recovered Fuel Costs - earns a return | | $ | 37,262 | | $ | - | | 1 year | | $ | 758 | | $ | 1,639 | | 1 year |
| | | | | | | | | | | | | | | | | | | | | | |
| Noncurrent Regulatory Assets | | | | | | | | | | | | | | | | |
| 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 | | $ | - | | | | $ | 1,239 | | $ | - | | |
| | | | Other Regulatory Assets Not Yet Being Recovered | | | 574 | | | 850 | | | | | 613 | | | 471 | | |
| Total Regulatory Assets Not Yet Being Recovered | | | 17,830 | | | 850 | | | | | 1,852 | | | 471 | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Regulatory assets being recovered: | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | Regulatory Assets Currently Earning a Return | | | | | | | | | | | | | | | | |
| | | | Storm Related Costs | | | 38,499 | | | 53,366 | | 3 years | | | - | | | 3,043 | | |
| | | | Red Rock Generating Facility | | | 10,406 | | | 10,631 | | 46 years | | | - | | | - | | |
| | | | Unamortized Loss on Reacquired Debt | | | 8,277 | | | 10,175 | | 9 years | | | 12,422 | | | 13,118 | | 33 years |
| | | | Acquisition of Valley Electric Membership | | | | | | | | | | | | | | | | |
| | | | | Corporation (VEMCO) | | | - | | | - | | | | | 6,500 | | | - | | 5 years |
| | | | Lawton Settlement | | | - | | | 9,396 | | | | | - | | | - | | |
| | Regulatory Assets Currently Not Earning a Return | | | | | | | | | | | | | | | | |
| | | | Pension and OPEB Funded Status | | | 166,333 | | | 172,420 | | 13 years | | | 163,870 | | | 174,974 | | 13 years |
| | | | Vegetation Management | | | 13,303 | | | 16,014 | | 1 year | | | - | | | - | | |
| | | | Deferral of Major Generation Overhauls | | | 4,083 | | | 5,083 | | 4 years | | | - | | | - | | |
| | | | Energy Efficiency/Peak Demand Reduction | | | 3,705 | | | 88 | | 1 year | | | 495 | | | 1 | | 1 year |
| | | | Income Taxes, Net | | | 691 | | | - | | 34 years | | | 132,118 | | | 72,174 | | 29 years |
| | | | Unrealized Loss on Forward Commitments | | | 285 | | | 331 | | 3 years | | | 2,975 | | | 73 | | 3 years |
| | | | Storm Related Costs | | | - | | | - | | | | | 4,800 | | | - | | 3 years |
| | | | Rate Case Expense | | | - | | | - | | | | | 4,606 | | | - | | 3 years |
| | | | Dolet Hills Deferred Fuel | | | - | | | - | | | | | 2,725 | | | 3,353 | | 4 years |
| | | | Other Regulatory Assets Being Recovered | | | 133 | | | 831 | | various | | | 335 | | | 958 | | various |
| Total Regulatory Assets Being Recovered | | | 245,715 | | | 278,335 | | | | | 330,846 | | | 267,694 | | |
| | | | | | | | | | | | | | | | | |
| Total Noncurrent Regulatory Assets | | $ | 263,545 | | $ | 279,185 | | | | $ | 332,698 | | $ | 268,165 | | |
| | | | | | | | PSO | | SWEPCo |
| | | | | | | | | | Remaining | | | | Remaining |
| | | | | | | | December 31, | | Refund | | December 31, | | Refund |
| | | | | | | | 2010 | | 2009 | | Period | | 2010 | | 2009 | | Period |
| Regulatory Liabilities: | | (in thousands) | | | | (in thousands) | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Current Regulatory Liability | | | | | | | | | | | | | | | | |
| Over-recovered Fuel Costs - pays a return | | $ | - | | $ | 51,087 | | | | $ | 16,432 | | $ | 13,762 | | 1 year |
| | | | | | | | | | | | | | | | | |
| Noncurrent Regulatory Liabilities and | | | | | | | | | | | | | | | | |
| Deferred Investment Tax Credits | | | | | | | | | | | | | | | | |
| Regulatory liabilities not yet being paid: | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| | Regulatory Liabilities Currently Paying a Return | | | | | | | | | | | | | | | | |
| | | | Refundable Construction Financing Costs | | $ | - | | $ | - | | | | $ | 20,139 | | $ | - | | |
| | Regulatory Liabilities Currently Not Paying a Return | | | | | | | | | | | | | | | | |
| | | | Over-recovery of Costs Related to gridSMART® | | | 3,806 | | | 1,833 | | | | | - | | | - | | |
| | | | Over-recovery of Storm Related Costs | | | 3,493 | | | - | | | | | - | | | - | | |
| | | | Excess Earnings | | | - | | | - | | | | | - | (a) | | 3,167 | | |
| | | | Other Regulatory Liabilities Not Yet Being Paid | | | - | | | 1,171 | | | | | 806 | | | 1,006 | | |
| Total Regulatory Liabilities Not Yet Being Paid | | | 7,299 | | | 3,004 | | | | | 20,945 | | | 4,173 | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Regulatory liabilities being paid: | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | Regulatory Liabilities Currently Paying a Return | | | | | | | | | | | | | | | | |
| | | | Asset Removal Costs | | | 284,230 | | | 283,683 | | (b) | | | 346,402 | | | 308,590 | | (b) |
| | | | Excess Earnings | | | - | | | - | | | | | 3,119 | (a) | | - | | 43 years |
| | | | Other Regulatory Liabilities Being Paid | | | - | | | - | | | | | 1,667 | | | 2,054 | | various |
| | Regulatory Liabilities Currently Not Paying a Return | | | | | | | | | | | | | | | | |
| | | | Deferred Investment Tax Credits | | | 41,166 | | | 31,541 | | 38 years | | | 13,868 | | | 15,352 | | 28 years |
| | | | Energy Efficiency/Peak Demand Reduction | | | 4,266 | | | 1,120 | | 1 year | | | - | | | 64 | | |
| | | | Vegetation Management | | | - | | | - | | | | | 5,672 | | | - | | 2 years |
| | | | Income Taxes, Net | | | - | | | 5,431 | | | | | - | | | - | | |
| | | | Other Regulatory Liabilities Being Paid | | | - | | | 2,152 | | | | | 2,000 | | | 3,702 | | various |
| Total Regulatory Liabilities Being Paid | | | 329,662 | | | 323,927 | | | | | 372,728 | | | 329,762 | | |
| | | | | | | | | | | | | | | | | |
| Total Noncurrent Regulatory Liabilities and | | | | | | | | | | | | | | | | |
| | Deferred Investment Tax Credits | | $ | 336,961 | | $ | 326,931 | | | | $ | 393,673 | | $ | 333,935 | | |
| | | | | | | | | | | | | | | | | |
| (a) | | Payment of regulatory liability was granted during 2010. |
| (b) | | Relieved as removal costs are incurred. |
6. 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.
COMMITMENTS
Construction and Commitments – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo
The Registrant Subsidiaries have substantial construction commitments to support their operations and environmental investments. In managing the overall construction program and in the normal course of business, the Registrant Subsidiaries contractually commit to third-party construction vendors for certain material purchases and other construction services. The following table shows the forecasted construction expenditures excluding AFUDC and capitalized interest by Registrant Subsidiary for 2011:
| | | Forecasted | |
| | | Construction | |
| Company | | Expenditures | |
| | | (in millions) | |
| APCo | | $ | 450 | |
| CSPCo | | | 187 | |
| I&M | | | 305 | |
| OPCo | | | 264 | |
| PSO | | | 169 | |
| SWEPCo | | | 442 | |
The Registrant Subsidiaries purchase fuel, materials, supplies, services and property, plant and equipment under contract as part of their normal course of business. Certain supply contracts contain penalty provisions for early termination.
The following tables summarize the Registrant Subsidiaries’ actual contractual commitments at December 31, 2010:
| | | | Less Than 1 | | | | | | After | | |
| | Contractual Commitments - APCo | | year | | 2-3 years | | 4-5 years | | 5 years | | Total |
| | | | | | | | | | | | | | | | | | |
| | | | (in millions) |
| | Fuel Purchase Contracts (a) | | $ | 541.7 | | $ | 790.8 | | $ | 487.5 | | $ | 419.7 | | $ | 2,239.7 |
| | Energy and Capacity Purchase Contracts (b) | | | 16.4 | | | 27.3 | | | 27.0 | | | 186.4 | | | 257.1 |
| | Total | | $ | 558.1 | | $ | 818.1 | | $ | 514.5 | | $ | 606.1 | | $ | 2,496.8 |
| | | | | | | | | | | | | | | | | | |
| | | | Less Than 1 | | | | | | After | | |
| | Contractual Commitments - CSPCo | | year | | 2-3 years | | 4-5 years | | 5 years | | Total |
| | | | (in millions) |
| | Fuel Purchase Contracts (a) | | $ | 254.1 | | $ | 426.9 | | $ | 323.2 | | $ | 497.5 | | $ | 1,501.7 |
| | Energy and Capacity Purchase Contracts (b) | | | 5.3 | | | 7.1 | | | 2.7 | | | 16.9 | | | 32.0 |
| | Total | | $ | 259.4 | | $ | 434.0 | | $ | 325.9 | | $ | 514.4 | | $ | 1,533.7 |
| | | | | | | | | | | | | | | | | | |
| | | | Less Than 1 | | | | | | After | | |
| | Contractual Commitments - I&M | | year | | 2-3 years | | 4-5 years | | 5 years | | Total |
| | | | (in millions) |
| | Fuel Purchase Contracts (a) | | $ | 429.6 | | $ | 585.3 | | $ | 441.6 | | $ | 169.1 | | $ | 1,625.6 |
| | Energy and Capacity Purchase Contracts (b) | | | 2.5 | | | 1.2 | | | 0.4 | | | - | | | 4.1 |
| | Total | | $ | 432.1 | | $ | 586.5 | | $ | 442.0 | | $ | 169.1 | | $ | 1,629.7 |
| | | | | | | | | | | | | | | | | | |
| | | | Less Than 1 | | | | | | After | | |
| | Contractual Commitments - OPCo | | year | | 2-3 years | | 4-5 years | | 5 years | | Total |
| | | | (in millions) |
| | Fuel Purchase Contracts (a) | | $ | 887.8 | | $ | 1,546.7 | | $ | 1,184.4 | | $ | 2,551.6 | | $ | 6,170.5 |
| | Energy and Capacity Purchase Contracts (b) | | | 6.5 | | | 8.8 | | | 3.4 | | | 21.5 | | | 40.2 |
| | Total | | $ | 894.3 | | $ | 1,555.5 | | $ | 1,187.8 | | $ | 2,573.1 | | $ | 6,210.7 |
| | | | | | | | | | | | | | | | | | |
| | | | Less Than 1 | | | | | | After | | |
| | Contractual Commitments - PSO | | year | | 2-3 years | | 4-5 years | | 5 years | | Total |
| | | | (in millions) |
| | Fuel Purchase Contracts (a) | | $ | 256.6 | | $ | 113.8 | | $ | 30.1 | | $ | - | | $ | 400.5 |
| | Energy and Capacity Purchase Contracts (b) | | | 18.0 | | | 114.8 | | | 131.5 | | | 590.7 | | | 855.0 |
| | Total | | $ | 274.6 | | $ | 228.6 | | $ | 161.6 | | $ | 590.7 | | $ | 1,255.5 |
| | | | | | | | | | | | | | | | | | |
| | | | Less Than 1 | | | | | | After | | |
| | Contractual Commitments - SWEPCo | | year | | 2-3 years | | 4-5 years | | 5 years | | Total |
| | | | (in millions) |
| | Fuel Purchase Contracts (a) | | $ | 257.1 | | $ | 321.2 | | $ | 76.6 | | $ | 80.2 | | $ | 735.1 |
| | Energy and Capacity Purchase Contracts (b) | | | 19.0 | | | 39.1 | | | 39.2 | | | 284.9 | | | 382.2 |
| | Total | | $ | 276.1 | | $ | 360.3 | | $ | 115.8 | | $ | 365.1 | | $ | 1,117.3 |
| | | | | | | | | | | | | | | | | | |
| | (a) | Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. |
| | (b) | Represents contractual commitments for energy and capacity purchase contracts. |
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.
AEP has two $1.5 billion credit facilities, of which $750 million 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.
In June 2010, the Registrant Subsidiaries and certain other companies in the AEP System reduced a $627 million credit agreement to $478 million. As of December 31, 2010, $477 million of letters of credit were issued by Registrant Subsidiaries under the agreement to support variable rate Pollution Control Bonds.
At December 31, 2010, the maximum future payments of the letters of credit were as follows:
| | | | | | | | | | Borrower |
| | Company | | Amount | | Maturity | | Sublimit |
| | | | | (in thousands) | | | | (in thousands) |
| | $1.35 billion letters of credit: | | | | | | | | |
| | | I&M | | $ | 150 | | March 2011 | | | N/A |
| | | SWEPCo | | | 4,448 | | June 2011 | | | N/A |
| | | | | | | | | | | |
| | $478 million letter of credit: | | | | | | | | |
| | | APCo | | $ | 232,292 | | March 2011 to April 2011 | | $ | 300,000 |
| | | I&M | | | 77,886 | | April 2011 | | | 230,000 |
| | | OPCo | | | 166,899 | | April 2011 | | | 400,000 |
Guarantees of Third-Party Obligations – Affecting SWEPCo
As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation 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 December 31, 2010, SWEPCo has collected approximately $49 million through a rider for final mine closure and reclamatio n costs, of which $2 million is recorded in Other Current Liabilities, $25 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $22 million is recorded in Asset Retirement Obligations on SWEPCo’s 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. 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.
Lease Obligations
Certain Registrant Subsidiaries lease certain equipment under master lease agreements. See “Master Lease Agreements” and “Railcar Lease” sections of Note 13 for disclosure of lease residual value guarantees.
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 two liability trials, the jury 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 remaining claims in these cases. Beckjord is operated by Duke Energy Ohio, Inc.
Citizen Suit and Notice of Violation – 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 similar to the claims made in the citizen suit. 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 the citizen suit and has taken no further action. 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. 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. In December 2010, the defendants’ petition for review by the U.S. Supreme Court was granted. Briefing is underway and the case will be heard in April 2011. Management believes the actions are without merit and intends to continue to defend against the claims.
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;s decision in place. 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. The petition was denied in 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 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 ill 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. 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 APCo, CSPCo, I&M, OPCo, PSO and SWEPCo |
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.
Superfund addresses clean-up of hazardous substances that have been released to the environment. The Federal EPA administers the clean-up programs. Several states have enacted similar laws. At December 31, 2010, APCo and CSPCo are each named as a Potentially Responsible Party (PRP) for one site and OPCo is named a PRP for two sites by the Federal EPA. There are seven additional sites for which APCo, CSPCo, I&M, OPCo, and SWEPCo have received information requests which could lead to PRP designation. I&M and SWEPCo have also been named potentially liable at two sites each under state law including the I&M site discussed in the next paragraph. In those instances where the Registrant Subsidiaries have been named a PRP or defendant, disposal or recycling activit ies were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income.
In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ and recorded a provision of approximately $11 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.
Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often nonhazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. At present, management’s estimates do not anticipate material cleanup costs for identified Superfund sites, except the I&M site discussed above.
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 matter emission limits) that lasted for more than thirty 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 of these issues with DAQ, but cannot predict the outcome of these discussions or the amount of any penalty that may be assessed.
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 met with representatives of the Federal EPA. APCo and OPCo have not admitted that any violations occurred or that the amount of the proposed penalty is reasonable.
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 of the Cardinal Plant units and a Conesville Plant unit are operational. 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 were 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 2010, manage ment settled with Black & Veatch and resolved the issues involving the internal components and JBR vessel corrosion. These settlements resulted 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 (NRC). 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 liability could be substantial.
Decommissioning and Low Level Waste Accumulation Disposal
The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of the Cook Plant. The most recent decommissioning cost study was performed in 2009. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste ranges from $831 million to $1.5 billion in 2009 nondiscounted dollars. The wide range in estimated costs is caused by variables in assumptions. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amount recovered in rates was $14 million in 2010, $16 million in 2009 and $27 million in 2008. Reduced annual decommissioning cost recovery a mounts reflect the units’ longer estimated life and operating licenses granted by the NRC. Decommissioning costs recovered from customers are deposited in external trusts.
At December 31, 2010 and 2009, the total decommissioning trust fund balance was $1.2 billion and $1.1 billion, respectively. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability.
I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future net income, cash flows and possibly financial condition would be adversely affected if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered.
SNF Disposal
The Federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWH for fuel consumed after April 6, 1983 at the Cook Plant is being collected from customers and remitted to the U.S. Treasury. At December 31, 2010 and 2009, fees and related interest of $265 million and $265 million, respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $307 million and $306 million, respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program.
See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts.
Nuclear Incident Liability
I&M carries insurance coverage for property damage, decommissioning and decontamination at the Cook Plant in the amount of $1.8 billion. I&M purchases $1 billion of excess coverage for property damage, decommissioning and decontamination. Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes an industry mutual insurer for the placement of this insurance coverage. Participation in this mutual insurance requires a contingent financial obligation of up to $41 million for I&M which is assessable if the insurer’s financial resources would be inadequate to pay for losses.
The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public liability arising from a nuclear incident at $12.6 billion and covers any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $375 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $117.5 million on each licensed reactor in the U.S. payable in annual installments of $17.5 million. As a result, I&M could be assessed $235 million per nuclear incident payable in annual installments of $35 million. The number of incidents for which payments could be required is not limited.
In the event of an incident of a catastrophic nature, I&M is initially covered for the first $375 million through commercially available insurance. The next level of liability coverage of up to $12.2 billion would be covered by claims made under the Price-Anderson Act. If the liability were in excess of amounts recoverable from insurance and retrospective claim payments made under the Price-Anderson Act, I&M would seek to recover those amounts from customers through rate increases. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, net income, cash flows and financial condition could be adversely affected.
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. As of December 31, 2010, I&M recorded $46 million on its Consolidated Balance Sheet representing estimated recoverable amounts under the property insurance policy. Through December 31, 2010, 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. The treatment of the remaining accidental outage policy revenues through fuel clauses is discussed in “I&M Rate Matters” section of Note 4. 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 proceeding s are adverse, it could have an adverse impact on net income, cash flows and financial condition.
OPERATIONAL CONTINGENCIES
Insurance and Potential Losses – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo
The Registrant Subsidiaries maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third parties and are in excess of retentions absorbed by the Registrant Subsidiaries. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carri ers.
See “Nuclear Contingencies” section of this footnote for a discussion of I&M’s nuclear exposures and related insurance.
Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could have a material adverse effect on net income, cash flows and financial condition.
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.
I&M and Fort Wayne reached a settlement agreement. The agreement, signed in October 2010, is subject to approval by the IURC. I&M filed a petition with the IURC seeking approval. 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 rates of the payments made to Fort Wayne. If the agreement is not approved by 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 oiced 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 on board’s decision. BNSF appealed the U.S. District Court’s decision 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.
7. ACQUISITIONS
2010
Valley Electric Membership Corporation – Affecting SWEPCo
In November 2009, SWEPCo signed a letter of intent to purchase certain transmission and distribution assets of Valley Electric Membership Corporation (VEMCO). In October 2010, SWEPCo finalized the purchase for approximately $102 million and began serving VEMCO’s 30,000 customers in Louisiana.
2009
Oxbow Lignite Company and Red River Mining Company – Affecting SWEPCo
On December 29, 2009, SWEPCo purchased 50% of the Oxbow Lignite Company, LLC (OLC) membership interest for $13 million. CLECO acquired the remaining 50% membership interest in the OLC for $13 million. The Oxbow Mine is located near Coushatta, Louisiana and will be used as one of the fuel sources for SWEPCo’s and CLECO’s jointly-owned Dolet Hills Generating Station. SWEPCo will account for OLC as an equity investment. Also, on December 29, 2009, DHLC purchased mining equipment and assets for $16 million from the Red River Mining Company.
2008
None
8. BENEFIT PLANS
For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Investments Held in Trust for Future Liabilities” and “Fair Value Measurements of Assets and Liabilities” sections of Note 1.
The Registrant Subsidiaries participate in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide medical and life insurance benefits for retired employees.
Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrant Subsidiaries and the rate of compensation increase for each subsidiary.
The Registrant Subsidiaries recognize the funded status associated with defined benefit pension and OPEB plans in their balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrant Subsidiaries recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrant Subsidiaries record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. ; The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Actuarial Assumptions for Benefit Obligations
The weighted-average assumptions as of December 31 of each year used in the measurement of the Registrant Subsidiaries’ benefit obligations are shown in the following tables:
| | | | | | Other Postretirement |
| | | Pension Plans | | | Benefit Plans |
| Assumption | | 2010 | | 2009 | | | 2010 | | 2009 |
| Discount Rate | | 5.05 | % | | 5.60 | % | | | 5.25 | % | | 5.85 | % |
| | | Pension Plans |
| Assumption - Rate of Compensation Increase (a) | | 2010 | | 2009 |
| APCo | | 4.70 | % | | 4.35 | % |
| CSPCo | | 5.30 | % | | 4.95 | % |
| I&M | | 4.90 | % | | 4.55 | % |
| OPCo | | 4.90 | % | | 4.55 | % |
| PSO | | 4.95 | % | | 4.60 | % |
| SWEPCo | | 4.80 | % | | 4.45 | % |
| (a) | Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. |
A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds similar to those included in the Moody’s Aa bond index is constructed with a duration matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan. The discount rate is the same for each Registrant Subsidiary.
For 2010, the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 11.5% per year, with the average increase shown in the table above. The compensation increase rates reflect variations in each Registrant Subsidiary’s population participating in the pension plan.
Actuarial Assumptions for Net Periodic Benefit Costs
The weighted-average assumptions as of January 1 of each year used in the measurement of each Registrant Subsidiary’s benefit costs are shown in the following tables:
| | | | | | Other Postretirement |
| | | | Pension Plans | | Benefit Plans |
| Assumptions | | 2010 | | 2009 | | 2008 | | 2010 | | 2009 | | 2008 |
| Discount Rate | | 5.60 | % | | 6.00 | % | | 6.00 | % | | 5.85 | % | | 6.10 | % | | 6.20 | % |
| Expected Return on Plan Assets | | 8.00 | % | | 8.00 | % | | 8.00 | % | | 8.00 | % | | 7.75 | % | | 8.00 | % |
| | | |
| | | Pension Plans |
| Assumption - Rate of Compensation Increase | | 2010 | | 2009 | | 2008 |
| APCo | | 4.35 | % | | 5.65 | % | | 5.65 | % |
| CSP | | 4.95 | % | | 6.25 | % | | 6.25 | % |
| I&M | | 4.55 | % | | 5.85 | % | | 5.85 | % |
| OPCo | | 4.55 | % | | 5.85 | % | | 5.85 | % |
| PSO | | 4.60 | % | | 5.90 | % | | 5.90 | % |
| SWEPCo | | 4.45 | % | | 5.75 | % | | 5.75 | % |
The expected return on plan assets for 2010 was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation and current prospects for economic growth. The expected return on plan assets is the same for each Registrant Subsidiary.
The health care trend rate assumptions as of January 1 of each year used for OPEB plans measurement purposes are shown below:
| Health Care Trend Rates | | 2010 | | 2009 |
| Initial | | 8.00 | % | | 6.50 | % |
| Ultimate | | 5.00 | % | | 5.00 | % |
| Year Ultimate Reached | | 2016 | | 2012 |
Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects:
| | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in thousands) |
| Effect on Total Service and Interest Cost | | | | | | | | | | | | | | | | | | |
| | Components of Net Periodic Postretirement | | | | | | | | | | | | | | | | | | |
| | Health Care Benefit Cost: | | | | | | | | | | | | | | | | | | |
| | 1% Increase | | $ | 3,689 | | $ | 1,619 | | $ | 2,908 | | $ | 3,278 | | $ | 1,273 | | $ | 1,394 |
| | 1% Decrease | | | (2,965) | | | (1,302) | | | (2,343) | | | (2,636) | | | (1,026) | | | (1,123) |
| | | | | | | | | | | | | | | | | | | | |
| Effect on the Health Care Component of the | | | | | | | | | | | | | | | | | | |
| | Accumulated Postretirement Benefit | | | | | | | | | | | | | | | | | | |
| | Obligation: | | | | | | | | | | | | | | | | | | |
| | 1% Increase | | $ | 47,231 | | $ | 20,182 | | $ | 31,596 | | $ | 41,472 | | $ | 13,770 | | $ | 15,276 |
| | 1% Decrease | | | (38,564) | | | (16,501) | | | (25,905) | | | (33,902) | | | (11,297) | | | (12,533) |
Significant Concentrations of Risk within Plan Assets
In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. At December 31, 2010, the assets were invested in compliance with all investment limits. See “Inv estments Held in Trust for Future Liabilities” section of Note 1 for limit details.
Benefit Plan Obligations, Plan Assets and Funded Status as of December 31, 2010 and 2009
The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status as of December 31. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively.
| APCo | | | | Other Postretirement |
| | | Pension Plans | | Benefit Plans |
| | | 2010 | | 2009 | | 2010 | | 2009 |
| Change in Benefit Obligation | | (in thousands) |
| Benefit Obligation at January 1 | | $ | 632,832 | | $ | 585,806 | | $ | 348,787 | | $ | 333,140 |
| Service Cost | | | 12,908 | | | 12,689 | | | 5,722 | | | 5,142 |
| Interest Cost | | | 33,956 | | | 34,050 | | | 20,300 | | | 19,710 |
| Actuarial Loss | | | 28,909 | | | 34,389 | | | 33,656 | | | 8,892 |
| Plan Amendment Prior Service Credit | | | - | | | - | | | (4,257) | | | - |
| Benefit Payments | | | (56,386) | | | (34,102) | | | (27,677) | | | (24,188) |
| Participant Contributions | | | - | | | - | | | 4,782 | | | 4,243 |
| Medicare Subsidy | | | - | | | - | | | 1,839 | | | 1,848 |
| Benefit Obligation at December 31 | | $ | 652,219 | | $ | 632,832 | | $ | 383,152 | | $ | 348,787 |
| | | | | | | | | | | | | |
| Change in Fair Value of Plan Assets | | | | | | | | | | | | |
| Fair Value of Plan Assets at January 1 | | $ | 474,657 | | $ | 440,386 | | $ | 217,160 | | $ | 169,462 |
| Actual Gain on Plan Assets | | | 57,745 | | | 68,337 | | | 29,112 | | | 42,378 |
| Company Contributions | | | 36,820 | | | 36 | | | 20,394 | | | 25,265 |
| Participant Contributions | | | - | | | - | | | 4,782 | | | 4,243 |
| Benefit Payments | | | (56,386) | | | (34,102) | | | (27,677) | | | (24,188) |
| Fair Value of Plan Assets at December 31 | | $ | 512,836 | | $ | 474,657 | | $ | 243,771 | | $ | 217,160 |
| | | | | | | | | | | | | |
| Underfunded Status at December 31 | | $ | (139,383) | | $ | (158,175) | | $ | (139,381) | | $ | (131,627) |
| CSPCo | | | | Other Postretirement |
| | | Pension Plans | | Benefit Plans |
| | | 2010 | | 2009 | | 2010 | | 2009 |
| Change in Benefit Obligation | | (in thousands) |
| Benefit Obligation at January 1 | | $ | 364,891 | | $ | 344,638 | | $ | 151,161 | | $ | 150,885 |
| Service Cost | | | 5,873 | | | 5,504 | | | 2,761 | | | 2,470 |
| Interest Cost | | | 19,156 | | | 19,529 | | | 8,713 | | | 8,493 |
| Actuarial (Gain) Loss | | | 7,931 | | | 15,910 | | | 14,171 | | | (2,915) |
| Plan Amendment Prior Service Credit | | | - | | | - | | | (2,164) | | | - |
| Benefit Payments | | | (43,698) | | | (20,690) | | | (11,988) | | | (10,677) |
| Participant Contributions | | | - | | | - | | | 2,488 | | | 2,143 |
| Medicare Subsidy | | | - | | | - | | | 765 | | | 762 |
| Benefit Obligation at December 31 | | $ | 354,153 | | $ | 364,891 | | $ | 165,907 | | $ | 151,161 |
| | | | | | | | | | | | | |
| Change in Fair Value of Plan Assets | | | | | | | | | | | | |
| Fair Value of Plan Assets at January 1 | | $ | 288,468 | | $ | 271,342 | | $ | 98,754 | | $ | 81,350 |
| Actual Gain on Plan Assets | | | 28,825 | | | 37,816 | | | 12,208 | | | 14,808 |
| Company Contributions | | | 6,998 | | | - | | | 8,072 | | | 11,130 |
| Participant Contributions | | | - | | | - | | | 2,488 | | | 2,143 |
| Benefit Payments | | | (43,698) | | | (20,690) | | | (11,988) | | | (10,677) |
| Fair Value of Plan Assets at December 31 | | $ | 280,593 | | $ | 288,468 | | $ | 109,534 | | $ | 98,754 |
| | | | | | | | | | | | | |
| Underfunded Status at December 31 | | $ | (73,560) | | $ | (76,423) | | $ | (56,373) | | $ | (52,407) |
| I&M | | | | Other Postretirement |
| | | Pension Plans | | Benefit Plans |
| | | 2010 | | 2009 | | 2010 | | 2009 |
| Change in Benefit Obligation | | (in thousands) |
| Benefit Obligation at January 1 | | $ | 526,363 | | $ | 480,447 | | $ | 241,847 | | $ | 227,979 |
| Service Cost | | | 15,284 | | | 14,002 | | | 6,750 | | | 5,990 |
| Interest Cost | | | 29,085 | | | 28,520 | | | 14,164 | | | 13,675 |
| Actuarial Loss | | | 40,694 | | | 29,079 | | | 20,980 | | | 4,443 |
| Plan Amendment Prior Service Credit | | | - | | | - | | | (4,273) | | | - |
| Benefit Payments | | | (50,444) | | | (25,685) | | | (17,439) | | | (14,337) |
| Participant Contributions | | | - | | | - | | | 3,526 | | | 2,908 |
| Medicare Subsidy | | | - | | | - | | | 1,187 | | | 1,189 |
| Benefit Obligation at December 31 | | $ | 560,982 | | $ | 526,363 | | $ | 266,742 | | $ | 241,847 |
| | | | | | | | | | | | | |
| Change in Fair Value of Plan Assets | | | | | | | | | | | | |
| Fair Value of Plan Assets at January 1 | | $ | 379,562 | | $ | 353,624 | | $ | 166,682 | | $ | 128,878 |
| Actual Gain on Plan Assets | | | 50,811 | | | 51,612 | | | 20,983 | | | 30,576 |
| Company Contributions | | | 71,759 | | | 11 | | | 14,938 | | | 18,657 |
| Participant Contributions | | | - | | | - | | | 3,526 | | | 2,908 |
| Benefit Payments | | | (50,444) | | | (25,685) | | | (17,439) | | | (14,337) |
| Fair Value of Plan Assets at December 31 | | $ | 451,688 | | $ | 379,562 | | $ | 188,690 | | $ | 166,682 |
| | | | | | | | | | | | | |
| Underfunded Status at December 31 | | $ | (109,294) | | $ | (146,801) | | $ | (78,052) | | $ | (75,165) |
| OPCo | | | | Other Postretirement |
| | | Pension Plans | | Benefit Plans |
| | | 2010 | | 2009 | | 2010 | | 2009 |
| Change in Benefit Obligation | | (in thousands) |
| Benefit Obligation at January 1 | | $ | 616,590 | | $ | 573,613 | | $ | 306,711 | | $ | 291,601 |
| Service Cost | | | 11,381 | | | 11,034 | | | 5,426 | | | 4,877 |
| Interest Cost | | | 32,744 | | | 33,100 | | | 17,785 | | | 17,325 |
| Actuarial Loss | | | 23,478 | | | 32,454 | | | 31,462 | | | 9,284 |
| Plan Amendment Prior Service Credit | | | - | | | - | | | (3,875) | | | - |
| Benefit Payments | | | (54,257) | | | (33,611) | | | (23,685) | | | (22,385) |
| Participant Contributions | | | - | | | - | | | 4,765 | | | 4,234 |
| Medicare Subsidy | | | - | | | - | | | 1,759 | | | 1,775 |
| Benefit Obligation at December 31 | | $ | 629,936 | | $ | 616,590 | | $ | 340,348 | | $ | 306,711 |
| | | | | | | | | | | | | |
| Change in Fair Value of Plan Assets | | | | | | | | | | | | |
| Fair Value of Plan Assets at January 1 | | $ | 468,300 | | $ | 435,694 | | $ | 200,797 | | $ | 157,255 |
| Actual Gain on Plan Assets | | | 52,940 | | | 66,153 | | | 26,258 | | | 39,214 |
| Company Contributions | | | 51,705 | | | 64 | | | 15,529 | | | 22,479 |
| Participant Contributions | | | - | | | - | | | 4,765 | | | 4,234 |
| Benefit Payments | | | (54,257) | | | (33,611) | | | (23,685) | | | (22,385) |
| Fair Value of Plan Assets at December 31 | | $ | 518,688 | | $ | 468,300 | | $ | 223,664 | | $ | 200,797 |
| | | | | | | | | | | | | |
| Underfunded Status at December 31 | | $ | (111,248) | | $ | (148,290) | | $ | (116,684) | | $ | (105,914) |
| PSO | | | | Other Postretirement |
| | | Pension Plans | | Benefit Plans |
| | | 2010 | | 2009 | | 2010 | | 2009 |
| Change in Benefit Obligation | | (in thousands) |
| Benefit Obligation at January 1 | | $ | 285,592 | | $ | 260,936 | | $ | 108,220 | | $ | 101,446 |
| Service Cost | | | 6,052 | | | 5,744 | | | 2,815 | | | 2,522 |
| Interest Cost | | | 14,888 | | | 15,369 | | | 6,360 | | | 6,154 |
| Actuarial (Gain) Loss | | | (1,047) | | | 18,364 | | | 7,540 | | | 2,434 |
| Plan Amendment Prior Service Credit | | | - | | | - | | | (2,408) | | | - |
| Benefit Payments | | | (37,305) | | | (14,821) | | | (8,049) | | | (6,510) |
| Participant Contributions | | | - | | | - | | | 1,763 | | | 1,472 |
| Medicare Subsidy | | | - | | | - | | | 694 | | | 702 |
| Benefit Obligation at December 31 | | $ | 268,180 | | $ | 285,592 | | $ | 116,935 | | $ | 108,220 |
| | | | | | | | | | | | | |
| Change in Fair Value of Plan Assets | | | | | | | | | | | | |
| Fair Value of Plan Assets at January 1 | | $ | 216,966 | | $ | 202,447 | | $ | 75,700 | | $ | 58,195 |
| Actual Gain on Plan Assets | | | 21,040 | | | 29,316 | | | 6,357 | | | 12,637 |
| Company Contributions | | | 12,875 | | | 24 | | | 8,146 | | | 9,906 |
| Participant Contributions | | | - | | | - | | | 1,763 | | | 1,472 |
| Benefit Payments | | | (37,305) | | | (14,821) | | | (8,049) | | | (6,510) |
| Fair Value of Plan Assets at December 31 | | $ | 213,576 | | $ | 216,966 | | $ | 83,917 | | $ | 75,700 |
| | | | | | | | | | | | | |
| Underfunded Status at December 31 | | $ | (54,604) | | $ | (68,626) | | $ | (33,018) | | $ | (32,520) |
| SWEPCo | | | | Other Postretirement |
| | | Pension Plans | | Benefit Plans |
| | | 2010 | | 2009 | | 2010 | | 2009 |
| Change in Benefit Obligation | | (in thousands) |
| Benefit Obligation at January 1 | | $ | 288,081 | | $ | 257,749 | | $ | 118,571 | | $ | 110,689 |
| Service Cost | | | 7,046 | | | 6,757 | | | 3,108 | | | 2,817 |
| Interest Cost | | | 15,093 | | | 15,557 | | | 6,940 | | | 6,735 |
| Actuarial (Gain) Loss | | | (2,014) | | | 23,126 | | | 9,084 | | | 2,453 |
| Plan Amendment Prior Service Credit | | | - | | | - | | | (2,399) | | | - |
| Benefit Payments | | | (41,000) | | | (15,108) | | | (8,125) | | | (6,347) |
| Participant Contributions | | | - | | | - | | | 1,907 | | | 1,579 |
| Medicare Subsidy | | | - | | | - | | | 640 | | | 645 |
| Benefit Obligation at December 31 | | $ | 267,206 | | $ | 288,081 | | $ | 129,726 | | $ | 118,571 |
| | | | | | | | | | | | | |
| Change in Fair Value of Plan Assets | | | | | | | | | | | | |
| Fair Value of Plan Assets at January 1 | | $ | 212,626 | | $ | 194,816 | | $ | 82,940 | | $ | 63,498 |
| Actual Gain on Plan Assets | | | 23,854 | | | 32,840 | | | 8,150 | | | 14,035 |
| Company Contributions | | | 29,138 | | | 78 | | | 8,225 | | | 10,175 |
| Participant Contributions | | | - | | | - | | | 1,907 | | | 1,579 |
| Benefit Payments | | | (41,000) | | | (15,108) | | | (8,125) | | | (6,347) |
| Fair Value of Plan Assets at December 31 | | $ | 224,618 | | $ | 212,626 | | $ | 93,097 | | $ | 82,940 |
| | | | | | | | | | | | | |
| Underfunded Status at December 31 | | $ | (42,588) | | $ | (75,455) | | $ | (36,629) | | $ | (35,631) |
| Amounts Recognized on the Registrant Subsidiaries' Balance Sheets as of December 31, 2010 and 2009 |
| | | | | | | | | | | | | | | |
| | | | | | | Other Postretirement |
| | | | | Pension Plans | | Benefit Plans |
| | | | | December 31, |
| | APCo | | 2010 | | 2009 | | 2010 | | 2009 |
| | | | | (in thousands) |
| | Other Current Liabilities - Accrued Short-term | | | | | | | | | | | | |
| | | Benefit Liability | | $ | (34) | | $ | (35) | | $ | (2,854) | | $ | (2,705) |
| | Employee Benefits and Pension Obligations - | | | | | | | | | | | | |
| | | Accrued Long-term Benefit Liability | | | (139,349) | | | (158,140) | | | (136,527) | | | (128,922) |
| | Underfunded Status | | $ | (139,383) | | $ | (158,175) | | $ | (139,381) | | $ | (131,627) |
| | | | | | | Other Postretirement |
| | | | | Pension Plans | | Benefit Plans |
| | | | | December 31, |
| | CSPCo | | 2010 | | 2009 | | 2010 | | 2009 |
| | | | | (in thousands) |
| | Other Current Liabilities - Accrued Short-term | | | | | | | | | | | | |
| | | Benefit Liability | | $ | - | | $ | - | | $ | (363) | | $ | (338) |
| | Employee Benefits and Pension Obligations - | | | | | | | | | | | | |
| | | Accrued Long-term Benefit Liability | | | (73,560) | | | (76,423) | | | (56,010) | | | (52,069) |
| | Underfunded Status | | $ | (73,560) | | $ | (76,423) | | $ | (56,373) | | $ | (52,407) |
| | | | | | | Other Postretirement |
| | | | | Pension Plans | | Benefit Plans |
| | | | | December 31, |
| | I&M | | 2010 | | 2009 | | 2010 | | 2009 |
| | | | | (in thousands) |
| | Other Current Liabilities - Accrued Short-term | | | | | | | | | | | | |
| | | Benefit Liability | | $ | (57) | | $ | (87) | | $ | (313) | | $ | (327) |
| | Deferred Credits and Other Noncurrent Liabilities | | | | | | | | | | | | |
| | | Accrued Long-term Benefit Liability | | | (109,237) | | | (146,714) | | | (77,739) | | | (74,838) |
| | Underfunded Status | | $ | (109,294) | | $ | (146,801) | | $ | (78,052) | | $ | (75,165) |
| | | | | | | Other Postretirement |
| | | | | Pension Plans | | Benefit Plans |
| | | | | December 31, |
| | OPCo | | 2010 | | 2009 | | 2010 | | 2009 |
| | | | | (in thousands) |
| | Other Current Liabilities - Accrued Short-term | | | | | | | | | | | | |
| | | Benefit Liability | | $ | (59) | | $ | (64) | | $ | (304) | | $ | (240) |
| | Employee Benefits and Pension Obligations - | | | | | | | | | | | | |
| | | Accrued Long-term Benefit Liability | | | (111,189) | | | (148,226) | | | (116,380) | | | (105,674) |
| | Underfunded Status | | $ | (111,248) | | $ | (148,290) | | $ | (116,684) | | $ | (105,914) |
| | | | | | | Other Postretirement |
| | | | | Pension Plans | | Benefit Plans |
| | | | | December 31, |
| | PSO | | 2010 | | 2009 | | 2010 | | 2009 |
| | | | | (in thousands) |
| | Other Current Liabilities - Accrued Short-term | | | | | | | | | | | | |
| | | Benefit Liability | | $ | (68) | | $ | (97) | | $ | - | | $ | - |
| | Employee Benefits and Pension Obligations - | | | | | | | | | | | | |
| | | Accrued Long-term Benefit Liability | | | (54,536) | | | (68,529) | | | (33,018) | | | (32,520) |
| | Underfunded Status | | $ | (54,604) | | $ | (68,626) | | $ | (33,018) | | $ | (32,520) |
| | | | | | | Other Postretirement |
| | | | | Pension Plans | | Benefit Plans |
| | | | | December 31, |
| | SWEPCo | | 2010 | | 2009 | | 2010 | | 2009 |
| | | | | (in thousands) |
| | Other Current Liabilities - Accrued Short-term | | | | | | | | | | | | |
| | | Benefit Liability | | $ | (73) | | $ | (75) | | $ | - | | $ | - |
| | Employee Benefits and Pension Obligations - | | | | | | | | | | | | |
| | | Accrued Long-term Benefit Liability | | | (42,515) | | | (75,380) | | | (36,629) | | | (35,631) |
| | Underfunded Status | | $ | (42,588) | | $ | (75,455) | | $ | (36,629) | | $ | (35,631) |
| Amounts Included in AOCI and Regulatory Assets as of December 31, 2010 and 2009 |
| | |
| | | | | | Other Postretirement |
| APCo | | Pension Plans | | Benefit Plans |
| | | | December 31, |
| | | | 2010 | | 2009 | | 2010 | | 2009 |
| Components | | (in thousands) |
| Net Actuarial Loss | | $ | 290,798 | | $ | 287,871 | | $ | 115,350 | | $ | 96,884 |
| Prior Service Cost (Credit) | | | 2,310 | | | 3,227 | | | (2,086) | | | - |
| Transition Obligation | | | - | | | - | | | 1,947 | | | 9,362 |
| | | | | | | | | | | | | | |
| Recorded as | | | | | | | | | | | | |
| Regulatory Assets | | $ | 289,214 | | $ | 286,995 | | $ | 45,891 | | $ | 44,636 |
| Deferred Income Taxes | | | 1,366 | | | 1,439 | | | 23,881 | | | 21,213 |
| Net of Tax AOCI | | | 2,528 | | | 2,664 | | | 45,439 | | | 40,397 |
| | | | | | Other Postretirement |
| CSPCo | | Pension Plans | | Benefit Plans |
| | | | December 31, |
| | | | 2010 | | 2009 | | 2010 | | 2009 |
| Components | | (in thousands) |
| Net Actuarial Loss | | $ | 200,755 | | $ | 202,025 | | $ | 51,305 | | $ | 43,708 |
| Prior Service Cost (Credit) | | | 1,292 | | | 1,856 | | | (898) | | | - |
| Transition Obligation | | | - | | | - | | | 74 | | | 3,771 |
| | | | | | | | | | | | | | |
| Recorded as | | | | | | | | | | | | |
| Regulatory Assets | | $ | 144,607 | | $ | 146,082 | | $ | 29,148 | | $ | 28,942 |
| Deferred Income Taxes | | | 20,104 | | | 20,230 | | | 7,467 | | | 6,489 |
| Net of Tax AOCI | | | 37,336 | | | 37,569 | | | 13,866 | | | 12,048 |
| | | | | | Other Postretirement |
| I&M | | Pension Plans | | Benefit Plans |
| | | | December 31, |
| | | | 2010 | | 2009 | | 2010 | | 2009 |
| Components | | (in thousands) |
| Net Actuarial Loss | | $ | 208,879 | | $ | 194,212 | | $ | 78,483 | | $ | 68,637 |
| Prior Service Cost (Credit) | | | 2,051 | | | 2,795 | | | (2,882) | | | - |
| Transition Obligation | | | - | | | - | | | 320 | | | 4,525 |
| | | | | | | | | | | | | | |
| Recorded as | | | | | | | | | | | | |
| Regulatory Assets | | $ | 199,982 | | $ | 186,367 | | $ | 68,098 | | $ | 65,644 |
| Deferred Income Taxes | | | 3,830 | | | 3,723 | | | 2,737 | | | 2,630 |
| Net of Tax AOCI | | | 7,118 | | | 6,917 | | | 5,086 | | | 4,888 |
| | | | | | Other Postretirement |
| OPCo | | Pension Plans | | Benefit Plans |
| | | | December 31, |
| | | | 2010 | | 2009 | | 2010 | | 2009 |
| Components | | (in thousands) |
| Net Actuarial Loss | | $ | 296,277 | | $ | 286,851 | | $ | 107,571 | | $ | 90,839 |
| Prior Service Cost (Credit) | | | 2,207 | | | 3,115 | | | (1,699) | | | - |
| Transition Obligation | | | - | | | - | | | 180 | | | 6,566 |
| | | | | | | | | | | | | | |
| Recorded as | | | | | | | | | | | | |
| Regulatory Assets | | $ | 148,095 | | $ | 146,818 | | $ | 41,981 | | $ | 41,331 |
| Deferred Income Taxes | | | 52,637 | | | 49,332 | | | 22,421 | | | 19,626 |
| Net of Tax AOCI | | | 97,752 | | | 93,816 | | | 41,650 | | | 36,448 |
| | | | | | Other Postretirement |
| PSO | | Pension Plans | | Benefit Plans |
| | | | December 31, |
| | | | 2010 | | 2009 | | 2010 | | 2009 |
| Components | | (in thousands) |
| Net Actuarial Loss | | $ | 134,101 | | $ | 141,636 | | $ | 33,922 | | $ | 28,212 |
| Prior Service Credit | | | (769) | | | (1,720) | | | (921) | | | - |
| Transition Obligation | | | - | | | - | | | - | | | 4,292 |
| | | | | | | | | | | | | | |
| Recorded as | | | | | | | | | | | | |
| Regulatory Assets | | $ | 133,332 | | $ | 139,916 | | $ | 33,001 | | $ | 32,504 |
| | | | | | Other Postretirement |
| SWEPCo | | Pension Plans | | Benefit Plans |
| | | | December 31, |
| | | | 2010 | | 2009 | | 2010 | | 2009 |
| Components | | (in thousands) |
| Net Actuarial Loss | | $ | 131,343 | | $ | 142,964 | | $ | 37,707 | | $ | 31,848 |
| Prior Service Credit | | | (235) | | | (1,031) | | | (1,095) | | | - |
| Transition Obligation | | | - | | | - | | | - | | | 3,765 |
| | | | | | | | | | | | | | |
| Recorded as | | | | | | | | | | | | |
| Regulatory Assets | | $ | 131,108 | | $ | 141,933 | | $ | 23,842 | | $ | 23,221 |
| Deferred Income Taxes | | | - | | | - | | | 4,469 | | | 4,336 |
| Net of Tax AOCI | | | - | | | - | | | 8,301 | | | 8,056 |
Components of the change in amounts included in AOCI and Regulatory Assets by Registrant Subsidiary during the years ended December 31, 2010 and 2009 are as follows:
| Pension Plans - Components | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in thousands) |
| Actuarial Loss (Gain) During the Year | | $ | 14,769 | | $ | 5,439 | | $ | 24,732 | | $ | 20,869 | | $ | (2,346) | | $ | (6,379) |
| Amortization of Actuarial Loss | | | (11,842) | | | (6,708) | | | (10,065) | | | (11,442) | | | (5,188) | | | (5,242) |
| Amortization of Prior Service Cost (Credit) | | | (917) | | | (565) | | | (744) | | | (909) | | | 950 | | | 796 |
| Change for the Year Ended | | | | | | | | | | | | | | | | | | |
| | December 31, 2010 | $ | 2,010 | | $ | (1,834) | | $ | 13,923 | | $ | 8,518 | | $ | (6,584) | | $ | (10,825) |
| | | | | | | | | | | | | | | | | | | | |
| Pension Plans - Components | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in thousands) |
| Actuarial Loss During the Year | | $ | 10,937 | | $ | 5,372 | | $ | 13,200 | | $ | 10,579 | | $ | 9,484 | | $ | 10,367 |
| Amortization of Actuarial Loss | | | (7,688) | | | (4,431) | | | (6,406) | | | (7,500) | | | (3,487) | | | (3,516) |
| Amortization of Prior Service Cost (Credit) | | | (917) | | | (565) | | | (744) | | | (910) | | | 1,082 | | | 916 |
| Change for the Year Ended | | | | | | | | | | | | | | | | | | |
| | December 31, 2009 | $ | 2,332 | | $ | 376 | | $ | 6,050 | | $ | 2,169 | | $ | 7,079 | | $ | 7,767 |
| | | | | | | | | | | | | | | | | | | | |
| Other Postretirement Benefit Plans - Components | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in thousands) |
| Actuarial Loss During the Year | | $ | 23,876 | | $ | 9,858 | | $ | 13,372 | | $ | 21,349 | | $ | 7,283 | | $ | 7,570 |
| Amortization of Actuarial Loss | | | (5,410) | | | (2,261) | | | (3,526) | | | (4,616) | | | (1,573) | | | (1,711) |
| Prior Service Credit | | (4,257) | | | (2,164) | | | (4,273) | | | (3,875) | | | (2,408) | | | (2,399) |
| Amortization of Transition Obligation | | | (5,244) | | | (2,431) | | | (2,814) | | | (4,211) | | | (2,805) | | | (2,461) |
| Change for the Year Ended | | | | | | | | | | | | | | | | | | |
| | December 31, 2010 | $ | 8,965 | | $ | 3,002 | | $ | 2,759 | | $ | 8,647 | | $ | 497 | | $ | 999 |
| | | | | | | | | | | | | | | | | | | | |
| Other Postretirement Benefit Plans - Components | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in thousands) |
| Actuarial Gain During the Year | | $ | (21,375) | | $ | (11,976) | | $ | (16,408) | | $ | (18,761) | | $ | (5,577) | | $ | (6,540) |
| Amortization of Actuarial Loss | | | (7,666) | | | (3,285) | | | (5,213) | | | (6,703) | | | (2,348) | | | (2,560) |
| Amortization of Transition Obligation | | | (5,244) | | | (2,432) | | | (2,814) | | | (4,211) | | | (2,805) | | | (2,461) |
| Change for the Year Ended | | | | | | | | | | | | | | | | | | |
| | December 31, 2009 | $ | (34,285) | | $ | (17,693) | | $ | (24,435) | | $ | (29,675) | | $ | (10,730) | | $ | (11,561) |
Pension and Other Postretirement Plans’ Assets
The following tables present the classification of pension plan assets within the fair value hierarchy by Registrant Subsidiary at December 31, 2010:
| | APCo | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 179,421 | | $ | 366 | | $ | - | | $ | - | | $ | 179,787 | | 35.1 | % |
| | | International | | | 53,559 | | | - | | | - | | | - | | | 53,559 | | 10.4 | % |
| | | Real Estate Investment Trusts | | | 14,932 | | | - | | | - | | | - | | | 14,932 | | 2.9 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | International | | | - | | | 21,619 | | | - | | | - | | | 21,619 | | 4.2 | % |
| | Subtotal - Equities | | | 247,912 | | | 21,985 | | | - | | | - | | | 269,897 | | 52.6 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 84,280 | | | - | | | - | | | 84,280 | | 16.4 | % |
| | | Corporate Debt | | | - | | | 89,296 | | | - | | | - | | | 89,296 | | 17.4 | % |
| | | Foreign Debt | | | - | | | 16,900 | | | - | | | - | | | 16,900 | | 3.3 | % |
| | | State and Local Government | | | - | | | 3,021 | | | - | | | - | | | 3,021 | | 0.6 | % |
| | | Other - Asset Backed | | | - | | | 6,798 | | | - | | | - | | | 6,798 | | 1.3 | % |
| | Subtotal - Fixed Income | | | - | | | 200,295 | | | - | | | - | | | 200,295 | | 39.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Real Estate | | | - | | | - | | | 11,060 | | | - | | | 11,060 | | 2.2 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Alternative Investments | | | - | | | - | | | 17,281 | | | - | | | 17,281 | | 3.4 | % |
| | Securities Lending | | | - | | | 33,804 | | | - | | | - | | | 33,804 | | 6.6 | % |
| | Securities Lending Collateral (a) | | | - | | | - | | | - | | | (36,664) | | | (36,664) | | (7.1) | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (b) | | | - | | | 16,870 | | | - | | | 212 | | | 17,082 | | 3.3 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (c) | | | - | | | - | | | - | | | 81 | | | 81 | | - | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 247,912 | | $ | 272,954 | | $ | 28,341 | | $ | (36,371) | | $ | 512,836 | | 100.0 | % |
| | CSPCo | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 98,168 | | $ | 200 | | $ | - | | $ | - | | $ | 98,368 | | 35.1 | % |
| | | International | | | 29,304 | | | - | | | - | | | - | | | 29,304 | | 10.4 | % |
| | | Real Estate Investment Trusts | | | 8,170 | | | - | | | - | | | - | | | 8,170 | | 2.9 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | International | | | - | | | 11,829 | | | - | | | - | | | 11,829 | | 4.2 | % |
| | Subtotal - Equities | | | 135,642 | | | 12,029 | | | - | | | - | | | 147,671 | | 52.6 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 46,113 | | | - | | | - | | | 46,113 | | 16.4 | % |
| | | Corporate Debt | | | - | | | 48,857 | | | - | | | - | | | 48,857 | | 17.4 | % |
| | | Foreign Debt | | | - | | | 9,247 | | | - | | | - | | | 9,247 | | 3.3 | % |
| | | State and Local Government | | | - | | | 1,653 | | | - | | | - | | | 1,653 | | 0.6 | % |
| | | Other - Asset Backed | | | - | | | 3,719 | | | - | | | - | | | 3,719 | | 1.3 | % |
| | Subtotal - Fixed Income | | | - | | | 109,589 | | | - | | | - | | | 109,589 | | 39.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Real Estate | | | - | | | - | | | 6,052 | | | - | | | 6,052 | | 2.2 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Alternative Investments | | | - | | | - | | | 9,455 | | | - | | | 9,455 | | 3.4 | % |
| | Securities Lending | | | - | | | 18,496 | | | - | | | - | | | 18,496 | | 6.6 | % |
| | Securities Lending Collateral (a) | | | - | | | - | | | - | | | (20,060) | | | (20,060) | | (7.1) | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (b) | | | - | | | 9,230 | | | - | | | 116 | | | 9,346 | | 3.3 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (c) | | | - | | | - | | | - | | | 44 | | | 44 | | - | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 135,642 | | $ | 149,344 | | $ | 15,507 | | $ | (19,900) | | $ | 280,593 | | 100.0 | % |
| | I&M | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 158,027 | | $ | 323 | | $ | - | | $ | - | | $ | 158,350 | | 35.1 | % |
| | �� | International | | | 47,173 | | | - | | | - | | | - | | | 47,173 | | 10.4 | % |
| | | Real Estate Investment Trusts | | | 13,152 | | | - | | | - | | | - | | | 13,152 | | 2.9 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | International | | | - | | | 19,041 | | | - | | | - | | | 19,041 | | 4.2 | % |
| | Subtotal - Equities | | | 218,352 | | | 19,364 | | | - | | | - | | | 237,716 | | 52.6 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 74,231 | | | - | | | - | | | 74,231 | | 16.4 | % |
| | | Corporate Debt | | | - | | | 78,649 | | | - | | | - | | | 78,649 | | 17.4 | % |
| | | Foreign Debt | | | - | | | 14,885 | | | - | | | - | | | 14,885 | | 3.3 | % |
| | | State and Local Government | | | - | | | 2,661 | | | - | | | - | | | 2,661 | | 0.6 | % |
| | | Other - Asset Backed | | | - | | | 5,987 | | | - | | | - | | | 5,987 | | 1.3 | % |
| | Subtotal - Fixed Income | | | - | | | 176,413 | | | - | | | - | | | 176,413 | | 39.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Real Estate | | | - | | | - | | | 9,742 | | | - | | | 9,742 | | 2.2 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Alternative Investments | | | - | | | - | | | 15,220 | | | - | | | 15,220 | | 3.4 | % |
| | Securities Lending | | | - | | | 29,773 | | | - | | | - | | | 29,773 | | 6.6 | % |
| | Securities Lending Collateral (a) | | | - | | | - | | | - | | | (32,292) | | | (32,292) | | (7.1) | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (b) | | | - | | | 14,859 | | | - | | | 186 | | | 15,045 | | 3.3 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (c) | | | - | | | - | | | - | | | 71 | | | 71 | | - | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 218,352 | | $ | 240,409 | | $ | 24,962 | | $ | (32,035) | | $ | 451,688 | | 100.0 | % |
| | OPCo | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 181,467 | | $ | 371 | | $ | - | | $ | - | | $ | 181,838 | | 35.1 | % |
| | | International | | | 54,169 | | | - | | | - | | | - | | | 54,169 | | 10.4 | % |
| | | Real Estate Investment Trusts | | | 15,103 | | | - | | | - | | | - | | | 15,103 | | 2.9 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | International | | | - | | | 21,866 | | | - | | | - | | | 21,866 | | 4.2 | % |
| | Subtotal - Equities | | | 250,739 | | | 22,237 | | | - | | | - | | | 272,976 | | 52.6 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 85,242 | | | - | | | - | | | 85,242 | | 16.4 | % |
| | | Corporate Debt | | | - | | | 90,315 | | | - | | | - | | | 90,315 | | 17.4 | % |
| | | Foreign Debt | | | - | | | 17,093 | | | - | | | - | | | 17,093 | | 3.3 | % |
| | | State and Local Government | | | - | | | 3,055 | | | - | | | - | | | 3,055 | | 0.6 | % |
| | | Other - Asset Backed | | | - | | | 6,875 | | | - | | | - | | | 6,875 | | 1.3 | % |
| | Subtotal - Fixed Income | | | - | | | 202,580 | | | - | | | - | | | 202,580 | | 39.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Real Estate | | | - | | | - | | | 11,187 | | | - | | | 11,187 | | 2.2 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Alternative Investments | | | - | | | - | | | 17,478 | | | - | | | 17,478 | | 3.4 | % |
| | Securities Lending | | | - | | | 34,190 | | | - | | | - | | | 34,190 | | 6.6 | % |
| | Securities Lending Collateral (a) | | | - | | | - | | | - | | | (37,082) | | | (37,082) | | (7.1) | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (b) | | | - | | | 17,063 | | | - | | | 214 | | | 17,277 | | 3.3 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (c) | | | - | | | - | | | - | | | 82 | | | 82 | | - | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 250,739 | | $ | 276,070 | | $ | 28,665 | | $ | (36,786) | | $ | 518,688 | | 100.0 | % |
| | PSO | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 74,721 | | $ | 153 | | $ | - | | $ | - | | $ | 74,874 | | 35.1 | % |
| | | International | | | 22,305 | | | - | | | - | | | - | | | 22,305 | | 10.4 | % |
| | | Real Estate Investment Trusts | | | 6,219 | | | - | | | - | | | - | | | 6,219 | | 2.9 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | International | | | - | | | 9,004 | | | - | | | - | | | 9,004 | | 4.2 | % |
| | Subtotal - Equities | | | 103,245 | | | 9,157 | | | - | | | - | | | 112,402 | | 52.6 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 35,099 | | | - | | | - | | | 35,099 | | 16.4 | % |
| | | Corporate Debt | | | - | | | 37,188 | | | - | | | - | | | 37,188 | | 17.4 | % |
| | | Foreign Debt | | | - | | | 7,038 | | | - | | | - | | | 7,038 | | 3.3 | % |
| | | State and Local Government | | | - | | | 1,258 | | | - | | | - | | | 1,258 | | 0.6 | % |
| | | Other - Asset Backed | | | - | | | 2,831 | | | - | | | - | | | 2,831 | | 1.3 | % |
| | Subtotal - Fixed Income | | | - | | | 83,414 | | | - | | | - | | | 83,414 | | 39.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Real Estate | | | - | | | - | | | 4,606 | | | - | | | 4,606 | | 2.2 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Alternative Investments | | | - | | | - | | | 7,197 | | | - | | | 7,197 | | 3.4 | % |
| | Securities Lending | | | - | | | 14,078 | | | - | | | - | | | 14,078 | | 6.6 | % |
| | Securities Lending Collateral (a) | | | - | | | - | | | - | | | (15,269) | | | (15,269) | | (7.1) | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (b) | | | - | | | 7,026 | | | - | | | 88 | | | 7,114 | | 3.3 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (c) | | | - | | | - | | | - | | | 34 | | | 34 | | - | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 103,245 | | $ | 113,675 | | $ | 11,803 | | $ | (15,147) | | $ | 213,576 | | 100.0 | % |
| | SWEPCo | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 78,585 | | $ | 160 | | $ | - | | $ | - | | $ | 78,745 | | 35.1 | % |
| | | International | | | 23,458 | | | - | | | - | | | - | | | 23,458 | | 10.4 | % |
| | | Real Estate Investment Trusts | | | 6,540 | | | - | | | - | | | - | | | 6,540 | | 2.9 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | International | | | - | | | 9,469 | | | - | | | - | | | 9,469 | | 4.2 | % |
| | Subtotal - Equities | | | 108,583 | | | 9,629 | | | - | | | - | | | 118,212 | | 52.6 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 36,914 | | | - | | | - | | | 36,914 | | 16.4 | % |
| | | Corporate Debt | | | - | | | 39,111 | | | - | | | - | | | 39,111 | | 17.4 | % |
| | | Foreign Debt | | | - | | | 7,402 | | | - | | | - | | | 7,402 | | 3.3 | % |
| | | State and Local Government | | | - | | | 1,323 | | | - | | | - | | | 1,323 | | 0.6 | % |
| | | Other - Asset Backed | | | - | | | 2,977 | | | - | | | - | | | 2,977 | | 1.3 | % |
| | Subtotal - Fixed Income | | | - | | | 87,727 | | | - | | | - | | | 87,727 | | 39.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Real Estate | | | - | | | - | | | 4,844 | | | - | | | 4,844 | | 2.2 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Alternative Investments | | | - | | | - | | | 7,569 | | | - | | | 7,569 | | 3.4 | % |
| | Securities Lending | | | - | | | 14,806 | | | - | | | - | | | 14,806 | | 6.6 | % |
| | Securities Lending Collateral (a) | | | - | | | - | | | - | | | (16,058) | | | (16,058) | | (7.1) | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (b) | | | - | | | 7,389 | | | - | | | 93 | | | 7,482 | | 3.3 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (c) | | | - | | | - | | | - | | | 36 | | | 36 | | - | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 108,583 | | $ | 119,551 | | $ | 12,413 | | $ | (15,929) | | $ | 224,618 | | 100.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | |
| | (a) | Amounts in "Other" column primarily represent an obligation to repay cash collateral received as part of the Securities |
| | | | | Lending Program. |
| | (b) | Amounts in "Other" column primarily represent foreign currency holdings. |
| | (c) | Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending |
| | | | | settlement. |
The following tables set forth a reconciliation of changes in the fair value of real estate and alternative investments classified as Level 3 in the fair value hierarchy by Registrant Subsidiary for pension assets:
| | | | | | | Alternative | | Total |
| | APCo | | Real Estate | | Investments | | Level 3 |
| | | | | (in thousands) |
| | Balance as of January 1, 2010 | | $ | 12,623 | | $ | 14,739 | | $ | 27,362 |
| | Actual Return on Plan Assets | | | | | | | | | |
| | | Relating to Assets Still Held as of the Reporting Date | | | (1,563) | | | 412 | | | (1,151) |
| | | Relating to Assets Sold During the Period | | | - | | | 134 | | | 134 |
| | Purchases and Sales | | | - | | | 1,996 | | | 1,996 |
| | Transfers into Level 3 | | | - | | | - | | | - |
| | Transfers out of Level 3 | | | - | | | - | | | - |
| | Balance as of December 31, 2010 | | $ | 11,060 | | $ | 17,281 | | $ | 28,341 |
| | | | | | | Alternative | | Total |
| | CSPCo | | Real Estate | | Investments | | Level 3 |
| | | | | (in thousands) |
| | Balance as of January 1, 2010 | | $ | 7,671 | | $ | 8,957 | | $ | 16,628 |
| | Actual Return on Plan Assets | | | | | | | | | |
| | | Relating to Assets Still Held as of the Reporting Date | | | (1,619) | | | 81 | | | (1,538) |
| | | Relating to Assets Sold During the Period | | | - | | | 26 | | | 26 |
| | Purchases and Sales | | | - | | | 391 | | | 391 |
| | Transfers into Level 3 | | | - | | | - | | | - |
| | Transfers out of Level 3 | | | - | | | - | | | - |
| | Balance as of December 31, 2010 | | $ | 6,052 | | $ | 9,455 | | $ | 15,507 |
| | | | | | | Alternative | | Total |
| | I&M | | Real Estate | | Investments | | Level 3 |
| | | | | (in thousands) |
| | Balance as of January 1, 2010 | | $ | 10,094 | | $ | 11,786 | | $ | 21,880 |
| | Actual Return on Plan Assets | | | | | | | | | |
| | | Relating to Assets Still Held as of the Reporting Date | | | (352) | | | 556 | | | 204 |
| | | Relating to Assets Sold During the Period | | | - | | | 181 | | | 181 |
| | Purchases and Sales | | | - | | | 2,697 | | | 2,697 |
| | Transfers into Level 3 | | | - | | | - | | | - |
| | Transfers out of Level 3 | | | - | | | - | | | - |
| | Balance as of December 31, 2010 | | $ | 9,742 | | $ | 15,220 | | $ | 24,962 |
| | | | | | | Alternative | | Total |
| | OPCo | | Real Estate | | Investments | | Level 3 |
| | | | | (in thousands) |
| | Balance as of January 1, 2010 | | $ | 12,454 | | $ | 14,541 | | $ | 26,995 |
| | Actual Return on Plan Assets | | | | | | | | | |
| | | Relating to Assets Still Held as of the Reporting Date | | | (1,267) | | | 476 | | | (791) |
| | | Relating to Assets Sold During the Period | | | - | | | 155 | | | 155 |
| | Purchases and Sales | | | - | | | 2,306 | | | 2,306 |
| | Transfers into Level 3 | | | - | | | - | | | - |
| | Transfers out of Level 3 | | | - | | | - | | | - |
| | Balance as of December 31, 2010 | | $ | 11,187 | | $ | 17,478 | | $ | 28,665 |
| | | | | | | Alternative | | Total |
| | PSO | | Real Estate | | Investments | | Level 3 |
| | | | | (in thousands) |
| | Balance as of January 1, 2010 | | $ | 5,770 | | $ | 6,737 | | $ | 12,507 |
| | Actual Return on Plan Assets | | | | | | | | | |
| | | Relating to Assets Still Held as of the Reporting Date | | | (1,164) | | | 75 | | | (1,089) |
| | | Relating to Assets Sold During the Period | | | - | | | 24 | | | 24 |
| | Purchases and Sales | | | - | | | 361 | | | 361 |
| | Transfers into Level 3 | | | - | | | - | | | - |
| | Transfers out of Level 3 | | | - | | | - | | | - |
| | Balance as of December 31, 2010 | | $ | 4,606 | | $ | 7,197 | | $ | 11,803 |
| | | | | | | Alternative | | Total |
| | SWEPCo | | Real Estate | | Investments | | Level 3 |
| | | | | (in thousands) |
| | Balance as of January 1, 2010 | | $ | 5,654 | | $ | 6,602 | | $ | 12,256 |
| | Actual Return on Plan Assets | | | | | | | | | |
| | | Relating to Assets Still Held as of the Reporting Date | | | (810) | | | 156 | | | (654) |
| | | Relating to Assets Sold During the Period | | | - | | | 51 | | | 51 |
| | Purchases and Sales | | | - | | | 760 | | | 760 |
| | Transfers into Level 3 | | | - | | | - | | | - |
| | Transfers out of Level 3 | | | - | | | - | | | - |
| | Balance as of December 31, 2010 | | $ | 4,844 | | $ | 7,569 | | $ | 12,413 |
The following tables present the classification of OPEB plan assets within the fair value hierarchy by Registrant Subsidiary at December 31, 2010:
| | APCo | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 97,469 | | $ | - | | $ | - | | $ | - | | $ | 97,469 | | 40.0 | % |
| | | International | | | 36,792 | | | - | | | - | | | - | | | 36,792 | | 15.1 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | Global | | | - | | | 19,153 | | | - | | | - | | | 19,153 | | 7.9 | % |
| | Subtotal - Equities | | | 134,261 | | | 19,153 | | | - | | | - | | | 153,414 | | 63.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | Common Collective Trust - Debt | | | - | | | 7,966 | | | - | | | - | | | 7,966 | | 3.3 | % |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 15,636 | | | - | | | - | | | 15,636 | | 6.4 | % |
| | | Corporate Debt | | | - | | | 18,365 | | | - | | | - | | | 18,365 | | 7.5 | % |
| | | Foreign Debt | | | - | | | 4,140 | | | - | | | - | | | 4,140 | | 1.7 | % |
| | | State and Local Government | | | - | | | 583 | | | - | | | - | | | 583 | | 0.2 | % |
| | | Other - Asset Backed | | | - | | | 158 | | | - | | | - | | | 158 | | 0.1 | % |
| | Subtotal - Fixed Income | | | - | | | 46,848 | | | - | | | - | | | 46,848 | | 19.2 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Trust Owned Life Insurance: | | | | | | | | | | | | | | | | | | |
| | | International Equities | | | - | | | 8,189 | | | - | | | - | | | 8,189 | | 3.3 | % |
| | | United States Bonds | | | - | | | 27,130 | | | - | | | - | | | 27,130 | | 11.1 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (a) | | | 3,422 | | | 4,179 | | | - | | | 143 | | | 7,744 | | 3.2 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (b) | | | - | | | - | | | - | | | 446 | | | 446 | | 0.2 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 137,683 | | $ | 105,499 | | $ | - | | $ | 589 | | $ | 243,771 | | 100.0 | % |
| | CSPCo | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 43,795 | | $ | - | | $ | - | | $ | - | | $ | 43,795 | | 40.0 | % |
| | | International | | | 16,532 | | | - | | | - | | | - | | | 16,532 | | 15.1 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | Global | | | - | | | 8,606 | | | - | | | - | | | 8,606 | | 7.9 | % |
| | Subtotal - Equities | | | 60,327 | | | 8,606 | | | - | | | - | | | 68,933 | | 63.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | Common Collective Trust - Debt | | | - | | | 3,580 | | | - | | | - | | | 3,580 | | 3.3 | % |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 7,026 | | | - | | | - | | | 7,026 | | 6.4 | % |
| | | Corporate Debt | | | - | | | 8,252 | | | - | | | - | | | 8,252 | | 7.5 | % |
| | | Foreign Debt | | | - | | | 1,860 | | | - | | | - | | | 1,860 | | 1.7 | % |
| | | State and Local Government | | | - | | | 262 | | | - | | | - | | | 262 | | 0.2 | % |
| | | Other - Asset Backed | | | - | | | 71 | | | - | | | - | | | 71 | | 0.1 | % |
| | Subtotal - Fixed Income | | | - | | | 21,051 | | | - | | | - | | | 21,051 | | 19.2 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Trust Owned Life Insurance: | | | | | | | | | | | | | | | | | | |
| | | International Equities | | | - | | | 3,679 | | | - | | | - | | | 3,679 | | 3.3 | % |
| | | United States Bonds | | | - | | | 12,190 | | | - | | | - | | | 12,190 | | 11.1 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (a) | | | 1,538 | | | 1,878 | | | - | | | 64 | | | 3,480 | | 3.2 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (b) | | | - | | | - | | | - | | | 201 | | | 201 | | 0.2 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 61,865 | | $ | 47,404 | | $ | - | | $ | 265 | | $ | 109,534 | | 100.0 | % |
| | I&M | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 75,446 | | $ | - | | $ | - | | $ | - | | $ | 75,446 | | 40.0 | % |
| | | International | | | 28,479 | | | - | | | - | | | - | | | 28,479 | | 15.1 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | Global | | | - | | | 14,825 | | | - | | | - | | | 14,825 | | 7.9 | % |
| | Subtotal - Equities | | | 103,925 | | | 14,825 | | | - | | | - | | | 118,750 | | 63.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | Common Collective Trust - Debt | | | - | | | 6,166 | | | - | | | - | | | 6,166 | | 3.3 | % |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 12,103 | | | - | | | - | | | 12,103 | | 6.4 | % |
| | | Corporate Debt | | | - | | | 14,215 | | | - | | | - | | | 14,215 | | 7.5 | % |
| | | Foreign Debt | | | - | | | 3,204 | | | - | | | - | | | 3,204 | | 1.7 | % |
| | | State and Local Government | | | - | | | 452 | | | - | | | - | | | 452 | | 0.2 | % |
| | | Other - Asset Backed | | | - | | | 122 | | | - | | | - | | | 122 | | 0.1 | % |
| | Subtotal - Fixed Income | | | - | | | 36,262 | | | - | | | - | | | 36,262 | | 19.2 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Trust Owned Life Insurance: | | | | | | | | | | | | | | | | | | |
| | | International Equities | | | - | | | 6,338 | | | - | | | - | | | 6,338 | | 3.3 | % |
| | | United States Bonds | | | - | | | 21,000 | | | - | | | - | | | 21,000 | | 11.1 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (a) | | | 2,649 | | | 3,234 | | | - | | | 111 | | | 5,994 | | 3.2 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (b) | | | - | | | - | | | - | | | 346 | | | 346 | | 0.2 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 106,574 | | $ | 81,659 | | $ | - | | $ | 457 | | $ | 188,690 | | 100.0 | % |
| | OPCo | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 89,430 | | $ | - | | $ | - | | $ | - | | $ | 89,430 | | 40.0 | % |
| | | International | | | 33,758 | | | - | | | - | | | - | | | 33,758 | | 15.1 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | Global | | | - | | | 17,573 | | | - | | | - | | | 17,573 | | 7.9 | % |
| | | | | Subtotal Equities | | | 123,188 | | | 17,573 | | | - | | | - | | | 140,761 | | 63.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | Common Collective Trust - Debt | | | - | | | 7,309 | | | - | | | - | | | 7,309 | | 3.3 | % |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 14,346 | | | - | | | - | | | 14,346 | | 6.4 | % |
| | | Corporate Debt | | | - | | | 16,850 | | | - | | | - | | | 16,850 | | 7.5 | % |
| | | Foreign Debt | | | - | | | 3,798 | | | - | | | - | | | 3,798 | | 1.7 | % |
| | | State and Local Government | | | - | | | 535 | | | - | | | - | | | 535 | | 0.2 | % |
| | | Other - Asset Backed | | | - | | | 145 | | | - | | | - | | | 145 | | 0.1 | % |
| | | | | Subtotal Fixed Income | | | - | | | 42,983 | | | - | | | - | | | 42,983 | | 19.2 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Trust Owned Life Insurance: | | | | | | | | | | | | | | | | | | |
| | | International Equities | | | - | | | 7,513 | | | - | | | - | | | 7,513 | | 3.3 | % |
| | | United States Bonds | | | - | | | 24,892 | | | - | | | - | | | 24,892 | | 11.1 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (a) | | | 3,140 | | | 3,834 | | | - | | | 131 | | | 7,105 | | 3.2 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (b) | | | - | | | - | | | - | | | 410 | | | 410 | | 0.2 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 126,328 | | $ | 96,795 | | $ | - | | $ | 541 | | $ | 223,664 | | 100.0 | % |
| | PSO | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 33,555 | | $ | - | | $ | - | | $ | - | | $ | 33,555 | | 40.0 | % |
| | | International | | | 12,666 | | | - | | | - | | | - | | | 12,666 | | 15.1 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | Global | | | - | | | 6,593 | | | - | | | - | | | 6,593 | | 7.9 | % |
| | Subtotal - Equities | | | 46,221 | | | 6,593 | | | - | | | - | | | 52,814 | | 63.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | Common Collective Trust - Debt | | | - | | | 2,742 | | | - | | | - | | | 2,742 | | 3.3 | % |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 5,382 | | | - | | | - | | | 5,382 | | 6.4 | % |
| | | Corporate Debt | | | - | | | 6,322 | | | - | | | - | | | 6,322 | | 7.5 | % |
| | | Foreign Debt | | | - | | | 1,425 | | | - | | | - | | | 1,425 | | 1.7 | % |
| | | State and Local Government | | | - | | | 201 | | | - | | | - | | | 201 | | 0.2 | % |
| | | Other - Asset Backed | | | - | | | 54 | | | - | | | - | | | 54 | | 0.1 | % |
| | Subtotal - Fixed Income | | | - | | | 16,126 | | | - | | | - | | | 16,126 | | 19.2 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Trust Owned Life Insurance: | | | | | | | | | | | | | | | | | | |
| | | International Equities | | | - | | | 2,819 | | | - | | | - | | | 2,819 | | 3.3 | % |
| | | United States Bonds | | | - | | | 9,339 | | | - | | | - | | | 9,339 | | 11.1 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (a) | | | 1,178 | | | 1,438 | | | - | | | 49 | | | 2,665 | | 3.2 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (b) | | | - | | | - | | | - | | | 154 | | | 154 | | 0.2 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 47,399 | | $ | 36,315 | | $ | - | | $ | 203 | | $ | 83,917 | | 100.0 | % |
| | SWEPCo | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 37,225 | | $ | - | | $ | - | | $ | - | | $ | 37,225 | | 40.0 | % |
| | | International | | | 14,051 | | | - | | | - | | | - | | | 14,051 | | 15.1 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | Global | | | - | | | 7,314 | | | - | | | - | | | 7,314 | | 7.9 | % |
| | Subtotal - Equities | | | 51,276 | | | 7,314 | | | - | | | - | | | 58,590 | | 63.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | Common Collective Trust - Debt | | | - | | | 3,042 | | | - | | | - | | | 3,042 | | 3.3 | % |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 5,971 | | | - | | | - | | | 5,971 | | 6.4 | % |
| | | Corporate Debt | | | - | | | 7,014 | | | - | | | - | | | 7,014 | | 7.5 | % |
| | | Foreign Debt | | | - | | | 1,581 | | | - | | | - | | | 1,581 | | 1.7 | % |
| | | State and Local Government | | | - | | | 223 | | | - | | | - | | | 223 | | 0.2 | % |
| | | Other - Asset Backed | | | - | | | 60 | | | - | | | - | | | 60 | | 0.1 | % |
| | Subtotal - Fixed Income | | | - | | | 17,891 | | | - | | | - | | | 17,891 | | 19.2 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Trust Owned Life Insurance: | | | | | | | | | | | | | | | | | | |
| | | International Equities | | | - | | | 3,127 | | | - | | | - | | | 3,127 | | 3.3 | % |
| | | United States Bonds | | | - | | | 10,361 | | | - | | | - | | | 10,361 | | 11.1 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (a) | | | 1,307 | | | 1,596 | | | - | | | 55 | | | 2,958 | | 3.2 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (b) | | | - | | | - | | | - | | | 170 | | | 170 | | 0.2 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 52,583 | | $ | 40,289 | | $ | - | | $ | 225 | | $ | 93,097 | | 100.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | |
| | (a) | Amounts in "Other" column primarily represent foreign currency holdings. |
| | (b) | Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending |
| | | | | settlement. |
The following tables present the classification of pension plan assets within the fair value hierarchy by Registrant Subsidiary at December 31, 2009:
| | APCo | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 170,104 | | $ | - | | $ | - | | $ | - | | $ | 170,104 | | 35.8 | % |
| | | International | | | 44,620 | | | - | | | - | | | - | | | 44,620 | | 9.4 | % |
| | | Real Estate Investment Trusts | | | 12,089 | | | - | | | - | | | - | | | 12,089 | | 2.6 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | International | | | - | | | 22,468 | | | - | | | - | | | 22,468 | | 4.7 | % |
| | Subtotal - Equities | | | 226,813 | | | 22,468 | | | - | | | - | | | 249,281 | | 52.5 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 32,473 | | | - | | | - | | | 32,473 | | 6.9 | % |
| | | Corporate Debt | | | - | | | 115,879 | | | - | | | - | | | 115,879 | | 24.4 | % |
| | | Foreign Debt | | | - | | | 23,838 | | | - | | | - | | | 23,838 | | 5.0 | % |
| | | State and Local Government | | | - | | | 4,800 | | | - | | | - | | | 4,800 | | 1.0 | % |
| | | Other - Asset Backed | | | - | | | 3,822 | | | - | | | - | | | 3,822 | | 0.8 | % |
| | Subtotal - Fixed Income | | | - | | | 180,812 | | | - | | | - | | | 180,812 | | 38.1 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Real Estate | | | - | | | - | | | 12,623 | | | - | | | 12,623 | | 2.7 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Alternative Investments | | | - | | | - | | | 14,739 | | | - | | | 14,739 | | 3.1 | % |
| | Securities Lending | | | - | | | 24,179 | | | - | | | - | | | 24,179 | | 5.1 | % |
| | Securities Lending Collateral (a) | | | - | | | - | | | - | | | (27,313) | | | (27,313) | | (5.8) | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (b) | | | - | | | 16,126 | | | - | | | 562 | | | 16,688 | | 3.5 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (c) | | | - | | | - | | | - | | | 3,648 | | | 3,648 | | 0.8 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 226,813 | | $ | 243,585 | | $ | 27,362 | | $ | (23,103) | | $ | 474,657 | | 100.0 | % |
| | CSPCo | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 103,381 | | $ | - | | $ | - | | $ | - | | $ | 103,381 | | 35.8 | % |
| | | International | | | 27,117 | | | - | | | - | | | - | | | 27,117 | | 9.4 | % |
| | | Real Estate Investment Trusts | | | 7,347 | | | - | | | - | | | - | | | 7,347 | | 2.6 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | International | | | - | | | 13,655 | | | - | | | - | | | 13,655 | | 4.7 | % |
| | Subtotal - Equities | | | 137,845 | | | 13,655 | | | - | | | - | | | 151,500 | | 52.5 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 19,735 | | | - | | | - | | | 19,735 | | 6.9 | % |
| | | Corporate Debt | | | - | | | 70,425 | | | - | | | - | | | 70,425 | | 24.4 | % |
| | | Foreign Debt | | | - | | | 14,487 | | | - | | | - | | | 14,487 | | 5.0 | % |
| | | State and Local Government | | | - | | | 2,917 | | | - | | | - | | | 2,917 | | 1.0 | % |
| | | Other - Asset Backed | | | - | | | 2,323 | | | - | | | - | | | 2,323 | | 0.8 | % |
| | Subtotal - Fixed Income | | | - | | | 109,887 | | | - | | | - | | | 109,887 | | 38.1 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Real Estate | | | - | | | - | | | 7,671 | | | - | | | 7,671 | | 2.7 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Alternative Investments | | | - | | | - | | | 8,957 | | | - | | | 8,957 | | 3.1 | % |
| | Securities Lending | | | - | | | 14,694 | | | - | | | - | | | 14,694 | | 5.1 | % |
| | Securities Lending Collateral (a) | | | - | | | - | | | - | | | (16,599) | | | (16,599) | | (5.8) | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (b) | | | - | | | 9,800 | | | - | | | 341 | | | 10,141 | | 3.5 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (c) | | | - | | | - | | | - | | | 2,217 | | | 2,217 | | 0.8 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 137,845 | | $ | 148,036 | | $ | 16,628 | | $ | (14,041) | | $ | 288,468 | | 100.0 | % |
| | I&M | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 136,025 | | $ | - | | $ | - | | $ | - | | $ | 136,025 | | 35.8 | % |
| | | International | | | 35,680 | | | - | | | - | | | - | | | 35,680 | | 9.4 | % |
| | | Real Estate Investment Trusts | | | 9,667 | | | - | | | - | | | - | | | 9,667 | | 2.6 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | International | | | - | | | 17,967 | | | - | | | - | | | 17,967 | | 4.7 | % |
| | Subtotal - Equities | | | 181,372 | | | 17,967 | | | - | | | - | | | 199,339 | | 52.5 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 25,967 | | | - | | | - | | | 25,967 | | 6.9 | % |
| | | Corporate Debt | | | - | | | 92,664 | | | - | | | - | | | 92,664 | | 24.4 | % |
| | | Foreign Debt | | | - | | | 19,062 | | | - | | | - | | | 19,062 | | 5.0 | % |
| | | State and Local Government | | | - | | | 3,839 | | | - | | | - | | | 3,839 | | 1.0 | % |
| | | Other - Asset Backed | | | - | | | 3,056 | | | - | | | - | | | 3,056 | | 0.8 | % |
| | Subtotal - Fixed Income | | | - | | | 144,588 | | | - | | | - | | | 144,588 | | 38.1 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Real Estate | | | - | | | - | | | 10,094 | | | - | | | 10,094 | | 2.7 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Alternative Investments | | | - | | | - | | | 11,786 | | | - | | | 11,786 | | 3.1 | % |
| | Securities Lending | | | - | | | 19,335 | | | - | | | - | | | 19,335 | | 5.1 | % |
| | Securities Lending Collateral (a) | | | - | | | - | | | - | | | (21,841) | | | (21,841) | | (5.8) | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (b) | | | - | | | 12,895 | | | - | | | 449 | | | 13,344 | | 3.5 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (c) | | | - | | | - | | | - | | | 2,917 | | | 2,917 | | 0.8 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 181,372 | | $ | 194,785 | | $ | 21,880 | | $ | (18,475) | | $ | 379,562 | | 100.0 | % |
| | OPCo | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 167,827 | | $ | - | | $ | - | | $ | - | | $ | 167,827 | | 35.8 | % |
| | | International | | | 44,022 | | | - | | | - | | | - | | | 44,022 | | 9.4 | % |
| | | Real Estate Investment Trusts | | | 11,927 | | | - | | | - | | | - | | | 11,927 | | 2.6 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | International | | | - | | | 22,167 | | | - | | | - | | | 22,167 | | 4.7 | % |
| | Subtotal - Equities | | | 223,776 | | | 22,167 | | | - | | | - | | | 245,943 | | 52.5 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 32,038 | | | - | | | - | | | 32,038 | | 6.9 | % |
| | | Corporate Debt | | | - | | | 114,327 | | | - | | | - | | | 114,327 | | 24.4 | % |
| | | Foreign Debt | | | - | | | 23,519 | | | - | | | - | | | 23,519 | | 5.0 | % |
| | | State and Local Government | | | - | | | 4,736 | | | - | | | - | | | 4,736 | | 1.0 | % |
| | | Other - Asset Backed | | | - | | | 3,771 | | | - | | | - | | | 3,771 | | 0.8 | % |
| | Subtotal - Fixed Income | | | - | | | 178,391 | | | - | | | - | | | 178,391 | | 38.1 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Real Estate | | | - | | | - | | | 12,454 | | | - | | | 12,454 | | 2.7 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Alternative Investments | | | - | | | - | | | 14,541 | | | - | | | 14,541 | | 3.1 | % |
| | Securities Lending | | | - | | | 23,855 | | | - | | | - | | | 23,855 | | 5.1 | % |
| | Securities Lending Collateral (a) | | | - | | | - | | | - | | | (26,947) | | | (26,947) | | (5.8) | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (b) | | | - | | | 15,910 | | | - | | | 554 | | | 16,464 | | 3.5 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (c) | | | - | | | - | | | - | | | 3,599 | | | 3,599 | | 0.8 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 223,776 | | $ | 240,323 | | $ | 26,995 | | $ | (22,794) | | $ | 468,300 | | 100.0 | % |
| | PSO | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 77,756 | | $ | - | | $ | - | | $ | - | | $ | 77,756 | | 35.8 | % |
| | | International | | | 20,396 | | | - | | | - | | | - | | | 20,396 | | 9.4 | % |
| | | Real Estate Investment Trusts | | | 5,526 | | | - | | | - | | | - | | | 5,526 | | 2.6 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | International | | | - | | | 10,270 | | | - | | | - | | | 10,270 | | 4.7 | % |
| | Subtotal - Equities | | | 103,678 | | | 10,270 | | | - | | | - | | | 113,948 | | 52.5 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 14,843 | | | - | | | - | | | 14,843 | | 6.9 | % |
| | | Corporate Debt | | | - | | | 52,968 | | | - | | | - | | | 52,968 | | 24.4 | % |
| | | Foreign Debt | | | - | | | 10,896 | | | - | | | - | | | 10,896 | | 5.0 | % |
| | | State and Local Government | | | - | | | 2,194 | | | - | | | - | | | 2,194 | | 1.0 | % |
| | | Other - Asset Backed | | | - | | | 1,747 | | | - | | | - | | | 1,747 | | 0.8 | % |
| | Subtotal - Fixed Income | | | - | | | 82,648 | | | - | | | - | | | 82,648 | | 38.1 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Real Estate | | | - | | | - | | | 5,770 | | | - | | | 5,770 | | 2.7 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Alternative Investments | | | - | | | - | | | 6,737 | | | - | | | 6,737 | | 3.1 | % |
| | Securities Lending | | | - | | | 11,052 | | | - | | | - | | | 11,052 | | 5.1 | % |
| | Securities Lending Collateral (a) | | | - | | | - | | | - | | | (12,485) | | | (12,485) | | (5.8) | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (b) | | | - | | | 7,371 | | | - | | | 257 | | | 7,628 | | 3.5 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (c) | | | - | | | - | | | - | | | 1,668 | | | 1,668 | | 0.8 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 103,678 | | $ | 111,341 | | $ | 12,507 | | $ | (10,560) | | $ | 216,966 | | 100.0 | % |
| | SWEPCo | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 76,200 | | $ | - | | $ | - | | $ | - | | $ | 76,200 | | 35.8 | % |
| | | International | | | 19,988 | | | - | | | - | | | - | | | 19,988 | | 9.4 | % |
| | | Real Estate Investment Trusts | | | 5,415 | | | - | | | - | | | - | | | 5,415 | | 2.6 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | International | | | - | | | 10,065 | | | - | | | - | | | 10,065 | | 4.7 | % |
| | Subtotal - Equities | | | 101,603 | | | 10,065 | | | - | | | - | | | 111,668 | | 52.5 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 14,547 | | | - | | | - | | | 14,547 | | 6.9 | % |
| | | Corporate Debt | | | - | | | 51,909 | | | - | | | - | | | 51,909 | | 24.4 | % |
| | | Foreign Debt | | | - | | | 10,678 | | | - | | | - | | | 10,678 | | 5.0 | % |
| | | State and Local Government | | | - | | | 2,150 | | | - | | | - | | | 2,150 | | 1.0 | % |
| | | Other - Asset Backed | | | - | | | 1,712 | | | - | | | - | | | 1,712 | | 0.8 | % |
| | Subtotal - Fixed Income | | | - | | | 80,996 | | | - | | | - | | | 80,996 | | 38.1 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Real Estate | | | - | | | - | | | 5,654 | | | - | | | 5,654 | | 2.7 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Alternative Investments | | | - | | | - | | | 6,602 | | | - | | | 6,602 | | 3.1 | % |
| | Securities Lending | | | - | | | 10,831 | | | - | | | - | | | 10,831 | | 5.1 | % |
| | Securities Lending Collateral (a) | | | - | | | - | | | - | | | (12,235) | | | (12,235) | | (5.8) | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (b) | | | - | | | 7,224 | | | - | | | 252 | | | 7,476 | | 3.5 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (c) | | | - | | | - | | | - | | | 1,634 | | | 1,634 | | 0.8 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 101,603 | | $ | 109,116 | | $ | 12,256 | | $ | (10,349) | | $ | 212,626 | | 100.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | |
| | (a) | Amounts in "Other" column primarily represent an obligation to repay cash collateral received as part of the Securities |
| | | | | Lending Program. |
| | (b) | Amounts in "Other" column primarily represent foreign currency holdings. |
| | (c) | Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending |
| | | | | settlement. |
The following tables set forth a reconciliation of changes in the fair value of real estate and alternative investments classified as Level 3 in the fair value hierarchy for pension assets by Registrant Subsidiary:
| | | | | | | Alternative | | Total |
| | APCo | | Real Estate | | Investments | | Level 3 |
| | | | | (in thousands) |
| | Balance as of January 1, 2009 | | $ | 19,157 | | $ | 14,853 | | $ | 34,010 |
| | Actual Return on Plan Assets | | | | | | | | | |
| | | Relating to Assets Still Held as of the Reporting Date | | | (6,534) | | | (1,933) | | | (8,467) |
| | | Relating to Assets Sold During the Period | | | - | | | 58 | | | 58 |
| | Purchases and Sales | | | - | | | 1,761 | | | 1,761 |
| | Transfers in and/or out of Level 3 | | | - | | | - | | | - |
| | Balance as of December 31, 2009 | | $ | 12,623 | | $ | 14,739 | | $ | 27,362 |
| | | | | | | Alternative | | Total |
| | CSPCo | | Real Estate | | Investments | | Level 3 |
| | | | | (in thousands) |
| | Balance as of January 1, 2009 | | $ | 11,642 | | $ | 9,026 | | $ | 20,668 |
| | Actual Return on Plan Assets | | | | | | | | | |
| | | Relating to Assets Still Held as of the Reporting Date | | | (3,971) | | | (1,175) | | | (5,146) |
| | | Relating to Assets Sold During the Period | | | - | | | 35 | | | 35 |
| | Purchases and Sales | | | - | | | 1,071 | | | 1,071 |
| | Transfers in and/or out of Level 3 | | | - | | | - | | | - |
| | Balance as of December 31, 2009 | | $ | 7,671 | | $ | 8,957 | | $ | 16,628 |
| | | | | | | Alternative | | Total |
| | I&M | | Real Estate | | Investments | | Level 3 |
| | | | | (in thousands) |
| | Balance as of January 1, 2009 | | $ | 15,319 | | $ | 11,877 | | $ | 27,196 |
| | Actual Return on Plan Assets | | | | | | | | | |
| | | Relating to Assets Still Held as of the Reporting Date | | | (5,225) | | | (1,546) | | | (6,771) |
| | | Relating to Assets Sold During the Period | | | - | | | 46 | | | 46 |
| | Purchases and Sales | | | - | | | 1,409 | | | 1,409 |
| | Transfers in and/or out of Level 3 | | | - | | | - | | | - |
| | Balance as of December 31, 2009 | | $ | 10,094 | | $ | 11,786 | | $ | 21,880 |
| | | | | | | Alternative | | Total |
| | OPCo | | Real Estate | | Investments | | Level 3 |
| | | | | (in thousands) |
| | Balance as of January 1, 2009 | | $ | 18,900 | | $ | 14,653 | | $ | 33,553 |
| | Actual Return on Plan Assets | | | | | | | | | |
| | | Relating to Assets Still Held as of the Reporting Date | | | (6,446) | | | (1,907) | | | (8,353) |
| | | Relating to Assets Sold During the Period | | | - | | | 57 | | | 57 |
| | Purchases and Sales | | | - | | | 1,738 | | | 1,738 |
| | Transfers in and/or out of Level 3 | | | - | | | - | | | - |
| | Balance as of December 31, 2009 | | $ | 12,454 | | $ | 14,541 | | $ | 26,995 |
| | | | | | | Alternative | | Total |
| | PSO | | Real Estate | | Investments | | Level 3 |
| | | | | (in thousands) |
| | Balance as of January 1, 2009 | | $ | 8,757 | | $ | 6,790 | | $ | 15,547 |
| | Actual Return on Plan Assets | | | | | | | | | |
| | | Relating to Assets Still Held as of the Reporting Date | | | (2,987) | | | (884) | | | (3,871) |
| | | Relating to Assets Sold During the Period | | | - | | | 26 | | | 26 |
| | Purchases and Sales | | | - | | | 805 | | | 805 |
| | Transfers in and/or out of Level 3 | | | - | | | - | | | - |
| | Balance as of December 31, 2009 | | $ | 5,770 | | $ | 6,737 | | $ | 12,507 |
| | | | | | | Alternative | | Total |
| | SWEPCo | | Real Estate | | Investments | | Level 3 |
| | | | | (in thousands) |
| | Balance as of January 1, 2009 | | $ | 8,581 | | $ | 6,653 | | $ | 15,234 |
| | Actual Return on Plan Assets | | | | | | | | | |
| | | Relating to Assets Still Held as of the Reporting Date | | | (2,927) | | | (866) | | | (3,793) |
| | | Relating to Assets Sold During the Period | | | - | | | 26 | | | 26 |
| | Purchases and Sales | | | - | | | 789 | | | 789 |
| | Transfers in and/or out of Level 3 | | | - | | | - | | | - |
| | Balance as of December 31, 2009 | | $ | 5,654 | | $ | 6,602 | | $ | 12,256 |
The following tables present the classification of OPEB plan assets within the fair value hierarchy by Registrant Subsidiary at December 31, 2009:
| | APCo | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 57,049 | | $ | - | | $ | - | | $ | - | | $ | 57,049 | | 26.2 | % |
| | | International | | | 62,241 | | | - | | | - | | | - | | | 62,241 | | 28.7 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | Global | | | - | | | 15,468 | | | - | | | - | | | 15,468 | | 7.1 | % |
| | Subtotal - Equities | | | 119,290 | | | 15,468 | | | - | | | - | | | 134,758 | | 62.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | Common Collective Trust - Debt | | | - | | | 6,302 | | | - | | | - | | | 6,302 | | 2.9 | % |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 6,955 | | | - | | | - | | | 6,955 | | 3.2 | % |
| | | Corporate Debt | | | - | | | 23,498 | | | - | | | - | | | 23,498 | | 10.8 | % |
| | | Foreign Debt | | | - | | | 5,334 | | | - | | | - | | | 5,334 | | 2.4 | % |
| | | State and Local Government | | | - | | | 996 | | | - | | | - | | | 996 | | 0.5 | % |
| | | Other - Asset Backed | | | - | | | 232 | | | - | | | - | | | 232 | | 0.2 | % |
| | Subtotal - Fixed Income | | | - | | | 43,317 | | | - | | | - | | | 43,317 | | 20.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Trust Owned Life Insurance: | | | | | | | | | | | | | | | | | | |
| | | International Equities | | | - | | | 12,369 | | | - | | | - | | | 12,369 | | 5.7 | % |
| | | United States Bonds | | | - | | | 21,759 | | | - | | | - | | | 21,759 | | 10.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (a) | | | 1,092 | | | 2,389 | | | - | | | 165 | | | 3,646 | | 1.7 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (b) | | | - | | | - | | | - | | | 1,311 | | | 1,311 | | 0.6 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 120,382 | | $ | 95,302 | | $ | - | | $ | 1,476 | | $ | 217,160 | | 100.0 | % |
| | CSPCo | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 25,942 | | $ | - | | $ | - | | $ | - | | $ | 25,942 | | 26.2 | % |
| | | International | | | 28,304 | | | - | | | - | | | - | | | 28,304 | | 28.7 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | Global | | | - | | | 7,034 | | | - | | | - | | | 7,034 | | 7.1 | % |
| | Subtotal - Equities | | | 54,246 | | | 7,034 | | | - | | | - | | | 61,280 | | 62.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | Common Collective Trust - Debt | | | - | | | 2,866 | | | - | | | - | | | 2,866 | | 2.9 | % |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 3,163 | | | - | | | - | | | 3,163 | | 3.2 | % |
| | | Corporate Debt | | | - | | | 10,686 | | | - | | | - | | | 10,686 | | 10.8 | % |
| | | Foreign Debt | | | - | | | 2,426 | | | - | | | - | | | 2,426 | | 2.4 | % |
| | | State and Local Government | | | - | | | 453 | | | - | | | - | | | 453 | | 0.5 | % |
| | | Other - Asset Backed | | | - | | | 106 | | | - | | | - | | | 106 | | 0.2 | % |
| | Subtotal - Fixed Income | | | - | | | 19,700 | | | - | | | - | | | 19,700 | | 20.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Trust Owned Life Insurance: | | | | | | | | | | | | | | | | | | |
| | | International Equities | | | - | | | 5,625 | | | - | | | - | | | 5,625 | | 5.7 | % |
| | | United States Bonds | | | - | | | 9,895 | | | - | | | - | | | 9,895 | | 10.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (a) | | | 497 | | | 1,086 | | | - | | | 75 | | | 1,658 | | 1.7 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (b) | | | - | | | - | | | - | | | 596 | | | 596 | | 0.6 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 54,743 | | $ | 43,340 | | $ | - | | $ | 671 | | $ | 98,754 | | 100.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | |
| | I&M | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 43,790 | | $ | - | | $ | - | | $ | - | | $ | 43,790 | | 26.2 | % |
| | | International | | | 47,773 | | | - | | | - | | | - | | | 47,773 | | 28.7 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | Global | | | - | | | 11,873 | | | - | | | - | | | 11,873 | | 7.1 | % |
| | Subtotal - Equities | | | 91,563 | | | 11,873 | | | - | | | - | | | 103,436 | | 62.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | Common Collective Trust - Debt | | | - | | | 4,837 | | | - | | | - | | | 4,837 | | 2.9 | % |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 5,338 | | | - | | | - | | | 5,338 | | 3.2 | % |
| | | Corporate Debt | | | - | | | 18,036 | | | - | | | - | | | 18,036 | | 10.8 | % |
| | | Foreign Debt | | | - | | | 4,094 | | | - | | | - | | | 4,094 | | 2.4 | % |
| | | State and Local Government | | | - | | | 764 | | | - | | | - | | | 764 | | 0.5 | % |
| | | Other - Asset Backed | | | - | | | 178 | | | - | | | - | | | 178 | | 0.2 | % |
| | Subtotal - Fixed Income | | | - | | | 33,247 | | | - | | | - | | | 33,247 | | 20.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Trust Owned Life Insurance: | | | | | | | | | | | | | | | | | | |
| | | International Equities | | | - | | | 9,494 | | | - | | | - | | | 9,494 | | 5.7 | % |
| | | United States Bonds | | | - | | | 16,701 | | | - | | | - | | | 16,701 | | 10.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (a) | | | 838 | | | 1,834 | | | - | | | 126 | | | 2,798 | | 1.7 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (b) | | | - | | | - | | | - | | | 1,006 | | | 1,006 | | 0.6 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 92,401 | | $ | 73,149 | | $ | - | | $ | 1,132 | | $ | 166,682 | | 100.0 | % |
| | OPCo | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 52,752 | | $ | - | | $ | - | | $ | - | | $ | 52,752 | | 26.2 | % |
| | | International | | | 57,551 | | | - | | | - | | | - | | | 57,551 | | 28.7 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | Global | | | - | | | 14,302 | | | - | | | - | | | 14,302 | | 7.1 | % |
| | Subtotal - Equities | | | 110,303 | | | 14,302 | | | - | | | - | | | 124,605 | | 62.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | Common Collective Trust - Debt | | | - | | | 5,827 | | | - | | | - | | | 5,827 | | 2.9 | % |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 6,431 | | | - | | | - | | | 6,431 | | 3.2 | % |
| | | Corporate Debt | | | - | | | 21,727 | | | - | | | - | | | 21,727 | | 10.8 | % |
| | | Foreign Debt | | | - | | | 4,932 | | | - | | | - | | | 4,932 | | 2.4 | % |
| | | State and Local Government | | | - | | | 921 | | | - | | | - | | | 921 | | 0.5 | % |
| | | Other - Asset Backed | | | - | | | 215 | | | - | | | - | | | 215 | | 0.2 | % |
| | Subtotal - Fixed Income | | | - | | | 40,053 | | | - | | | - | | | 40,053 | | 20.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Trust Owned Life Insurance: | | | | | | | | | | | | | | | | | | |
| | | International Equities | | | - | | | 11,437 | | | - | | | - | | | 11,437 | | 5.7 | % |
| | | United States Bonds | | | - | | | 20,119 | | | - | | | - | | | 20,119 | | 10.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (a) | | | 1,010 | | | 2,209 | | | - | | | 152 | | | 3,371 | | 1.7 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (b) | | | - | | | - | | | - | | | 1,212 | | | 1,212 | | 0.6 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 111,313 | | $ | 88,120 | | $ | - | | $ | 1,364 | | $ | 200,797 | | 100.0 | % |
| | PSO | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 19,887 | | $ | - | | $ | - | | $ | - | | $ | 19,887 | | 26.2 | % |
| | | International | | | 21,697 | | | - | | | - | | | - | | | 21,697 | | 28.7 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | Global | | | - | | | 5,392 | | | - | | | - | | | 5,392 | | 7.1 | % |
| | Subtotal - Equities | | | 41,584 | | | 5,392 | | | - | | | - | | | 46,976 | | 62.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | Common Collective Trust - Debt | | | - | | | 2,197 | | | - | | | - | | | 2,197 | | 2.9 | % |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 2,424 | | | - | | | - | | | 2,424 | | 3.2 | % |
| | | Corporate Debt | | | - | | | 8,191 | | | - | | | - | | | 8,191 | | 10.8 | % |
| | | Foreign Debt | | | - | | | 1,859 | | | - | | | - | | | 1,859 | | 2.4 | % |
| | | State and Local Government | | | - | | | 347 | | | - | | | - | | | 347 | | 0.5 | % |
| | | Other - Asset Backed | | | - | | | 81 | | | - | | | - | | | 81 | | 0.2 | % |
| | Subtotal - Fixed Income | | | - | | | 15,099 | | | - | | | - | | | 15,099 | | 20.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Trust Owned Life Insurance: | | | | | | | | | | | | | | | | | | |
| | | International Equities | | | - | | | 4,312 | | | - | | | - | | | 4,312 | | 5.7 | % |
| | | United States Bonds | | | - | | | 7,585 | | | - | | | - | | | 7,585 | | 10.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (a) | | | 381 | | | 833 | | | - | | | 57 | | | 1,271 | | 1.7 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (b) | | | - | | | - | | | - | | | 457 | | | 457 | | 0.6 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 41,965 | | $ | 33,221 | | $ | - | | $ | 514 | | $ | 75,700 | | 100.0 | % |
| | SWEPCo | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | Year End |
| | Asset Class | | Level 1 | | Level 2 | | Level 3 | | Other | | Total | | Allocation |
| | | | (in thousands) |
| | Equities: | | | | | | | | | | | | | | | | | | |
| | | Domestic | | $ | 21,790 | | $ | - | | $ | - | | $ | - | | $ | 21,790 | | 26.2 | % |
| | | International | | | 23,772 | | | - | | | - | | | - | | | 23,772 | | 28.7 | % |
| | | Common Collective Trust - | | | | | | | | | | | | | | | | | | |
| | | | Global | | | - | | | 5,908 | | | - | | | - | | | 5,908 | | 7.1 | % |
| | Subtotal - Equities | | | 45,562 | | | 5,908 | | | - | | | - | | | 51,470 | | 62.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Fixed Income: | | | | | | | | | | | | | | | | | | |
| | | Common Collective Trust - Debt | | | - | | | 2,407 | | | - | | | - | | | 2,407 | | 2.9 | % |
| | | United States Government and | | | | | | | | | | | | | | | | | | |
| | | | Agency Securities | | | - | | | 2,656 | | | - | | | - | | | 2,656 | | 3.2 | % |
| | | Corporate Debt | | | - | | | 8,974 | | | - | | | - | | | 8,974 | | 10.8 | % |
| | | Foreign Debt | | | - | | | 2,037 | | | - | | | - | | | 2,037 | | 2.4 | % |
| | | State and Local Government | | | - | | | 380 | | | - | | | - | | | 380 | | 0.5 | % |
| | | Other - Asset Backed | | | - | | | 89 | | | - | | | - | | | 89 | | 0.2 | % |
| | Subtotal - Fixed Income | | | - | | | 16,543 | | | - | | | - | | | 16,543 | | 20.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Trust Owned Life Insurance: | | | | | | | | | | | | | | | | | | |
| | | International Equities | | | - | | | 4,724 | | | - | | | - | | | 4,724 | | 5.7 | % |
| | | United States Bonds | | | - | | | 8,310 | | | - | | | - | | | 8,310 | | 10.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Cash and Cash Equivalents (a) | | | 417 | | | 912 | | | - | | | 63 | | | 1,392 | | 1.7 | % |
| | Other - Pending Transactions and | | | | | | | | | | | | | | | | | | |
| | | Accrued Income (b) | | | - | | | - | | | - | | | 501 | | | 501 | | 0.6 | % |
| | | | | | | | | | | | | | | | | | | | |
| | Total | | $ | 45,979 | | $ | 36,397 | | $ | - | | $ | 564 | | $ | 82,940 | | 100.0 | % |
| | | | | | | | | | | | | | | | | | | | | | | |
| | (a) | Amounts in "Other" column primarily represent foreign currency holdings. |
| | (b) | Amounts in "Other" column primarily represent accrued interest, dividend receivables and transactions pending |
| | | | | settlement. |
Determination of Pension Expense
The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.
| Accumulated Benefit Obligation | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| Qualified Pension Plan | | $ | 646,513 | | $ | 350,150 | | $ | 551,702 | | $ | 623,652 | | $ | 261,535 | | $ | 260,838 |
| Nonqualified Pension Plans | | | 221 | | | 6 | | | 994 | | | 793 | | | 1,326 | | | 1,133 |
| Total as of December 31, 2010 | | $ | 646,734 | | $ | 350,156 | | $ | 552,696 | | $ | 624,445 | | $ | 262,861 | | $ | 261,971 |
| | | | | | | | | | | | | | | | | | | |
| Accumulated Benefit Obligation | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| Qualified Pension Plan | | $ | 626,533 | | $ | 362,037 | | $ | 515,338 | | $ | 611,120 | | $ | 281,452 | | $ | 284,143 |
| Nonqualified Pension Plans | | | 259 | | | 1 | | | 803 | | | 833 | | | 1,176 | | | 1,081 |
| Total as of December 31, 2009 | | $ | 626,792 | | $ | 362,038 | | $ | 516,141 | | $ | 611,953 | | $ | 282,628 | | $ | 285,224 |
For the underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets of these plans at December 31, 2010 and 2009 were as follows:
| | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in thousands) |
| Projected Benefit Obligation | $ | 652,219 | | $ | 354,153 | | $ | 560,982 | | $ | 629,936 | | $ | 268,180 | | $ | 267,206 |
| | | | | | | | | | | | | | | | | | | | |
| Accumulated Benefit Obligation | | $ | 646,734 | | $ | 350,156 | | $ | 552,696 | | $ | 624,445 | | $ | 262,861 | | $ | 261,971 |
| Fair Value of Plan Assets | | | 512,836 | | | 280,593 | | | 451,688 | | | 518,688 | | | 213,576 | | | 224,618 |
| Underfunded Accumulated Benefit | | | | | | | | | | | | | | | | | |
| | Obligation as of December 31, 2010 | | $ | (133,898) | | $ | (69,563) | | $ | (101,008) | | $ | (105,757) | | $ | (49,285) | | $ | (37,353) |
| | | | | | | | | | | | | | | | | | | | |
| | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in thousands) |
| Projected Benefit Obligation | $ | 632,832 | | $ | 364,891 | | $ | 526,363 | | $ | 616,590 | | $ | 285,592 | | $ | 288,081 |
| | | | | | | | | | | | | | | | | | | | |
| Accumulated Benefit Obligation | | $ | 626,792 | | $ | 362,038 | | $ | 516,141 | | $ | 611,953 | | $ | 282,628 | | $ | 285,224 |
| Fair Value of Plan Assets | | | 474,657 | | | 288,468 | | | 379,562 | | | 468,300 | | | 216,966 | | | 212,626 |
| Underfunded Accumulated Benefit | | | | | | | | | | | | | | | | | |
| | Obligation as of December 31, 2009 | | $ | (152,135) | | $ | (73,570) | | $ | (136,579) | | $ | (143,653) | | $ | (65,662) | | $ | (72,598) |
Estimated Future Benefit Payments and Contributions
The estimated pension benefit payments for the unfunded plan and contributions to the trust are at least the minimum amount required by ERISA plus payment of unfunded nonqualified benefits. For the qualified pension plan, additional discretionary contributions may be made to the trust to maintain the funded status of the plan. The contributions to the OPEB plans are generally based on the amount of the OPEB plans’ periodic benefit costs for accounting purposes as provided in agreements with state regulatory authorities, plus the additional discretionary contribution of the Medicare subsidy receipts. The following table provides the estimated contributions and payments by Registrant Subsidiary for 2011:
| | | | | Other Postretirement |
| Company | | Pension Plans | | Benefit Plans |
| | | (in thousands) |
| APCo | | $ | 14,735 | | $ | 15,032 |
| CSPCo | | | 4,958 | | | 5,544 |
| I&M | | | 21,087 | | | 11,756 |
| OPCo | | | 12,578 | | | 11,184 |
| PSO | | | 5,376 | | | 5,196 |
| SWEPCo | | | 7,287 | | | 5,539 |
The tables below reflect the total benefits expected to be paid from the plan or from the Registrant Subsidiary’s assets. The payments include the participants’ contributions to the plan for their share of the cost. Medicare subsidy receipts are shown in the year of the corresponding benefit payments, even though actual cash receipts are expected early in the following year. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for the pension benefits and OPEB are as follows:
| Pension Plans | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| 2011 | | $ | 43,369 | | $ | 27,274 | | $ | 33,768 | | $ | 43,315 | | $ | 19,313 | | $ | 19,103 |
| 2012 | | | 43,847 | | | 27,316 | | | 34,466 | | | 43,244 | | | 20,198 | | | 19,550 |
| 2013 | | | 44,073 | | | 27,164 | | | 35,638 | | | 43,140 | | | 20,601 | | | 20,207 |
| 2014 | | | 45,098 | | | 27,572 | | | 35,763 | | | 44,263 | | | 21,167 | | | 20,871 |
| 2015 | | | 45,333 | | | 27,496 | | | 37,269 | | | 44,398 | | | 21,585 | | | 22,063 |
| Years 2016 to 2020, in Total | | | 241,638 | | | 136,426 | | | 206,098 | | | 233,038 | | | 111,796 | | | 114,363 |
| | | | | | | | | | | | | | | | | | | |
| Other Postretirement Benefit Plans: Benefit Payments | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| 2011 | | $ | 27,094 | | $ | 12,259 | | $ | 17,682 | | $ | 23,622 | | $ | 8,136 | | $ | 8,321 |
| 2012 | | | 27,634 | | | 12,674 | | | 18,514 | | | 24,116 | | | 8,532 | | | 8,781 |
| 2013 | | | 28,353 | | | 13,095 | | | 19,297 | | | 24,493 | | | 9,016 | | | 9,274 |
| 2014 | | | 29,439 | | | 13,548 | | | 20,216 | | | 25,110 | | | 9,295 | | | 9,838 |
| 2015 | | | 30,306 | | | 13,751 | | | 21,129 | | | 26,036 | | | 9,774 | | | 10,300 |
| Years 2016 to 2020, in Total | | | 164,970 | | | 72,606 | | | 120,771 | | | 143,818 | | | 55,120 | | | 59,052 |
| | | | | | | | | | | | | | | | | | | |
| Other Postretirement Benefit Plans: Medicare Subsidy Receipts | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| 2011 | | $ | (2,086) | | $ | (836) | | $ | (1,322) | | $ | (1,862) | | $ | (754) | | $ | (704) |
| 2012 | | | (2,312) | | | (948) | | | (1,455) | | | (2,077) | | | (807) | | | (769) |
| 2013 | | | (2,508) | | | (1,057) | | | (1,592) | | | (2,273) | | | (863) | | | (830) |
| 2014 | | | (2,684) | | | (1,163) | | | (1,719) | | | (2,454) | | | (924) | | | (889) |
| 2015 | | | (2,865) | | | (1,284) | | | (1,846) | | | (2,616) | | | (973) | | | (956) |
| Years 2016 to 2020, in Total | | | (17,053) | | | (8,000) | | | (11,283) | | | (15,409) | | | (5,661) | | | (5,791) |
Components of Net Periodic Benefit Cost (Credit)
The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the years ended December 31, 2010, 2009 and 2008:
| | | | | | | Other Postretirement |
| | APCo | | Pension Plans | | Benefit Plans |
| | | | | Years Ended December 31, |
| | | | | 2010 | | 2009 | | 2008 | | 2010 | | 2009 | | 2008 |
| | | | | (in thousands) |
| | Service Cost | | $ | 12,908 | | $ | 12,689 | | $ | 12,407 | | $ | 5,722 | | $ | 5,142 | | $ | 5,228 |
| | Interest Cost | | | 33,956 | | | 34,050 | | | 33,852 | | | 20,300 | | | 19,710 | | | 20,578 |
| | Expected Return on Plan Assets | | | (43,805) | | | (44,885) | | | (46,855) | | | (17,628) | | | (13,531) | | | (18,793) |
| | Amortization of Transition Obligation | | | - | | | - | | | - | | | 5,244 | | | 5,244 | | | 5,244 |
| | Amortization of Prior Service Cost | | | 917 | | | 917 | | | 917 | | | - | | | - | | | - |
| | Amortization of Net Actuarial Loss | | | 11,842 | | | 7,688 | | | 3,016 | | | 5,410 | | | 7,666 | | | 2,639 |
| | Net Periodic Benefit Cost | | | 15,818 | | | 10,459 | | | 3,337 | | | 19,048 | | | 24,231 | | | 14,896 |
| | Capitalized Portion | | | (6,058) | | | (3,661) | | | (1,258) | | | (7,295) | | | (8,481) | | | (5,616) |
| | Net Periodic Benefit Cost Recognized as | | | | | | | | | | | | | | | | | | |
| | | Expense | | $ | 9,760 | | $ | 6,798 | | $ | 2,079 | | $ | 11,753 | | $ | 15,750 | | $ | 9,280 |
| | | | | | | Other Postretirement |
| | CSPCo | | Pension Plans | | Benefit Plans |
| | | | | Years Ended December 31, |
| | | | | 2010 | | 2009 | | 2008 | | 2010 | | 2009 | | 2008 |
| | | | | (in thousands) |
| | Service Cost | | $ | 5,873 | | $ | 5,504 | | $ | 5,367 | | $ | 2,761 | | $ | 2,470 | | $ | 2,435 |
| | Interest Cost | | | 19,156 | | | 19,529 | | | 19,804 | | | 8,713 | | | 8,493 | | | 9,327 |
| | Expected Return on Plan Assets | | | (26,357) | | | (27,277) | | | (28,905) | | | (7,916) | | | (6,126) | | | (9,080) |
| | Amortization of Transition Obligation | | | - | | | - | | | - | | | 2,431 | | | 2,432 | | | 2,431 |
| | Amortization of Prior Service Cost | | | 565 | | | 565 | | | 565 | | | - | | | - | | | - |
| | Amortization of Net Actuarial Loss | | | 6,708 | | | 4,431 | | | 1,771 | | | 2,261 | | | 3,285 | | | 928 |
| | Net Periodic Benefit Cost (Credit) | | | 5,945 | | | 2,752 | | | (1,398) | | | 8,250 | | | 10,554 | | | 6,041 |
| | Capitalized Portion | | | (1,891) | | | (900) | | | 509 | | | (2,624) | | | (3,451) | | | (2,199) |
| | Net Periodic Benefit Cost (Credit) | | | | | | | | | | | | | | | | | | |
| | | Recognized as Expense | | $ | 4,054 | | $ | 1,852 | | $ | (889) | | $ | 5,626 | | $ | 7,103 | | $ | 3,842 |
| | | | | | | Other Postretirement |
| | I&M | | Pension Plans | | Benefit Plans |
| | | | | Years Ended December 31, |
| | | | | 2010 | | 2009 | | 2008 | | 2010 | | 2009 | | 2008 |
| | | | | (in thousands) |
| | Service Cost | | $ | 15,284 | | $ | 14,002 | | $ | 13,573 | | $ | 6,750 | | $ | 5,990 | | $ | 5,944 |
| | Interest Cost | | | 29,085 | | | 28,520 | | | 27,959 | | | 14,164 | | | 13,675 | | | 14,006 |
| | Expected Return on Plan Assets | | | (35,040) | | | (35,733) | | | (37,466) | | | (13,397) | | | (10,259) | | | (14,067) |
| | Amortization of Transition Obligation | | | - | | | - | | | - | | | 2,814 | | | 2,814 | | | 2,814 |
| | Amortization of Prior Service Cost | | | 744 | | | 744 | | | 745 | | | - | | | - | | | - |
| | Amortization of Net Actuarial Loss | | | 10,065 | | | 6,406 | | | 2,472 | | | 3,526 | | | 5,213 | | | 1,068 |
| | Net Periodic Benefit Cost | | | 20,138 | | | 13,939 | | | 7,283 | | | 13,857 | | | 17,433 | | | 9,765 |
| | Capitalized Portion | | | (4,028) | | | (2,732) | | | (1,646) | | | (2,771) | | | (3,417) | | | (2,207) |
| | Net Periodic Benefit Cost Recognized as | | | | | | | | | | | | | | | | | | |
| | | Expense | | $ | 16,110 | | $ | 11,207 | | $ | 5,637 | | $ | 11,086 | | $ | 14,016 | | $ | 7,558 |
| | | | | | | Other Postretirement |
| | OPCo | | Pension Plans | | Benefit Plans |
| | | | | Years Ended December 31, |
| | | | | 2010 | | 2009 | | 2008 | | 2010 | | 2009 | | 2008 |
| | | | | (in thousands) |
| | Service Cost | | $ | 11,381 | | $ | 11,034 | | $ | 10,715 | | $ | 5,426 | | $ | 4,877 | | $ | 4,893 |
| | Interest Cost | | | 32,744 | | | 33,100 | | | 33,065 | | | 17,785 | | | 17,325 | | | 17,977 |
| | Expected Return on Plan Assets | | | (42,720) | | | (44,277) | | | (46,365) | | | (16,176) | | | (12,559) | | | (17,493) |
| | Amortization of Transition Obligation | | | - | | | - | | | - | | | 4,211 | | | 4,211 | | | 4,211 |
| | Amortization of Prior Service Cost | | | 909 | | | 910 | | | 913 | | | - | | | - | | | - |
| | Amortization of Net Actuarial Loss | | | 11,442 | | | 7,500 | | | 2,949 | | | 4,616 | | | 6,703 | | | 1,769 |
| | Net Periodic Benefit Cost | | | 13,756 | | | 8,267 | | | 1,277 | | | 15,862 | | | 20,557 | | | 11,357 |
| | Capitalized Portion | | | (4,952) | | | (3,001) | | | (476) | | | (5,710) | | | (7,462) | | | (4,236) |
| | Net Periodic Benefit Cost Recognized as | | | | | | | | | | | | | | | | | | |
| | | Expense | | $ | 8,804 | | $ | 5,266 | | $ | 801 | | $ | 10,152 | | $ | 13,095 | | $ | 7,121 |
| | | | | | | Other Postretirement |
| | PSO | | Pension Plans | | Benefit Plans |
| | | | | Years Ended December 31, |
| | | | | 2010 | | 2009 | | 2008 | | 2010 | | 2009 | | 2008 |
| | | | | (in thousands) |
| | Service Cost | | $ | 6,052 | | $ | 5,744 | | $ | 5,340 | | $ | 2,815 | | $ | 2,522 | | $ | 2,489 |
| | Interest Cost | | | 14,888 | | | 15,369 | | | 15,087 | | | 6,360 | | | 6,154 | | | 6,137 |
| | Expected Return on Plan Assets | | | (19,739) | | | (20,438) | | | (21,546) | | | (6,110) | | | (4,695) | | | (6,271) |
| | Amortization of Transition Obligation | | | - | | | - | | | - | | | 2,805 | | | 2,805 | | | 2,805 |
| | Amortization of Prior Service Credit | | | (950) | | | (1,082) | | | (1,081) | | | - | | | - | | | - |
| | Amortization of Net Actuarial Loss | | | 5,188 | | | 3,487 | | | 4,233 | | | 1,573 | | | 2,348 | | | 421 |
| | Net Periodic Benefit Cost | | | 5,439 | | | 3,080 | | | 2,033 | | | 7,443 | | | 9,134 | | | 5,581 |
| | Capitalized Portion | | | (1,806) | | | (1,087) | | | (777) | | | (2,471) | | | (3,224) | | | (2,132) |
| | Net Periodic Benefit Cost Recognized as | | | | | | | | | | | | | | | | | | |
| | | Expense | | $ | 3,633 | | $ | 1,993 | | $ | 1,256 | | $ | 4,972 | | $ | 5,910 | | $ | 3,449 |
| | | | | | | Other Postretirement |
| | SWEPCo | | Pension Plans | | Benefit Plans |
| | | | | Years Ended December 31, |
| | | | | 2010 | | 2009 | | 2008 | | 2010 | | 2009 | | 2008 |
| | | | | (in thousands) |
| | Service Cost | | $ | 7,046 | | $ | 6,757 | | $ | 6,284 | | $ | 3,108 | | $ | 2,817 | | $ | 2,745 |
| | Interest Cost | | | 15,093 | | | 15,557 | | | 14,961 | | | 6,940 | | | 6,735 | | | 6,694 |
| | Expected Return on Plan Assets | | | (19,489) | | | (20,083) | | | (20,751) | | | (6,646) | | | (5,120) | | | (6,819) |
| | Amortization of Transition Obligation | | | - | | | - | | | - | | | 2,461 | | | 2,461 | | | 2,461 |
| | Amortization of Prior Service Credit | | | (796) | | | (916) | | | (917) | | | - | | | - | | | - |
| | Amortization of Net Actuarial Loss | | | 5,242 | | | 3,516 | | | 4,165 | | | 1,711 | | | 2,560 | | | 458 |
| | Net Periodic Benefit Cost | | | 7,096 | | | 4,831 | | | 3,742 | | | 7,574 | | | 9,453 | | | 5,539 |
| | Capitalized Portion | | | (2,406) | | | (1,546) | | | (1,362) | | | (2,568) | | | (3,025) | | | (2,016) |
| | Net Periodic Benefit Cost Recognized as | | | | | | | | | | | | | | | | | | |
| | | Expense | | $ | 4,690 | | $ | 3,285 | | $ | 2,380 | | $ | 5,006 | | $ | 6,428 | | $ | 3,523 |
Estimated amounts expected to be amortized to net periodic benefit costs and the impact on each Registrant Subsidiary’s balance sheet during 2011 are shown in the following tables:
| | | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| Pension Plan - Components | | (in thousands) |
| Net Actuarial Loss | | $ | 16,342 | | $ | 8,873 | | $ | 14,061 | | $ | 15,787 | | $ | 6,727 | | $ | 6,701 |
| Prior Service Cost (Credit) | | | 917 | | | 565 | | | 744 | | | 909 | | | (950) | | | (795) |
| Total Estimated 2011 Amortization | $ | 17,259 | | $ | 9,438 | | $ | 14,805 | | $ | 16,696 | | $ | 5,777 | | $ | 5,906 |
| | | | | | | | | | | | | | | | | | | | |
| Pension Plans - | | | | | | | | | | | | | | | | | | |
| Expected to be Recorded as | | | | | | | | | | | | |
| Regulatory Asset | | $ | 17,168 | | $ | 6,470 | | $ | 13,917 | | $ | 7,614 | | $ | 5,777 | | $ | 5,906 |
| Deferred Income Taxes | | | 32 | | | 1,039 | | | 311 | | | 3,179 | | | - | | | - |
| Net of Tax AOCI | | | 59 | | | 1,929 | | | 577 | | | 5,903 | | | - | | | - |
| Total | $ | 17,259 | | $ | 9,438 | | $ | 14,805 | | $ | 16,696 | | $ | 5,777 | | $ | 5,906 |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | Other Postretirement Benefit Plans - | (in thousands) |
| | Components | | | | | | | | | | | | | | | | | | |
| Net Actuarial Loss | | $ | 6,423 | | $ | 2,700 | | $ | 4,085 | | $ | 5,560 | | $ | 1,766 | | $ | 1,960 |
| Prior Service Credit | | | (171) | | | (74) | | | (236) | | | (139) | | | (75) | | | (90) |
| Transition Obligation | | | 1,146 | | | 44 | | | 188 | | | 106 | | | - | | | - |
| Total Estimated 2011 Amortization | $ | 7,398 | | $ | 2,670 | | $ | 4,037 | | $ | 5,527 | | $ | 1,691 | | $ | 1,870 |
| | | | | | | | | | | | | | | | | | | | |
| Other Postretirement Benefit Plans - Expected to be Recorded as | | | | | | | | | | | | |
| Regulatory Asset | | $ | 2,419 | | $ | 1,523 | | $ | 3,419 | | $ | 2,190 | | $ | 1,691 | | $ | 1,215 |
| Deferred Income Taxes | | | 1,743 | | | 402 | | | 216 | | | 1,168 | | | - | | | 229 |
| Net of Tax AOCI | | | 3,236 | | | 745 | | | 402 | | | 2,169 | | | - | | | 426 |
| Total | $ | 7,398 | | $ | 2,670 | | $ | 4,037 | | $ | 5,527 | | $ | 1,691 | | $ | 1,870 |
American Electric Power System Retirement Savings Plans
The Registrant Subsidiaries participate in an AEP sponsored defined contribution retirement savings plan, the American Electric Power System Retirement Savings Plan, for substantially all employees who are not members of the United Mine Workers of America (UMWA). This qualified plan offers participants an opportunity to contribute a portion of their pay, includes features under Section 401(k) of the Internal Revenue Code and provides for company matching contributions. The matching contributions to the plan were 75% of the first 6% of eligible compensation contributed by the employee in 2008. Effective January 1, 2009, the match is 100% of the first 1% of eligible employee contributions and 70% of the next 5% of contributions.
The 2009 and 2008 contributions below for SWEPCo include a legacy savings plan of an acquired subsidiary.
The following table provides the cost for contributions to the retirement savings plans by Registrant Subsidiary for the years ended December 31, 2010, 2009 and 2008:
| | | | Years Ended December 31, |
| Company | | 2010 | | 2009 | | 2008 |
| | | | (in thousands) |
| APCo | | $ | 7,284 | | $ | 8,673 | | $ | 8,226 |
| CSPCo | | | 3,267 | | | 4,008 | | | 3,678 |
| I&M | | | 8,969 | | | 10,315 | | | 9,501 |
| OPCo | | | 6,439 | | | 7,632 | | | 7,246 |
| PSO | | | 3,505 | | | 4,083 | | | 3,933 |
| SWEPCo | | | 3,866 | | | 5,269 | | | 4,943 |
UMWA Benefits
APCo, CSPCo, I&M and OPCo provide UMWA pension, health and welfare benefits for certain unionized mining employees, retirees and their survivors who meet eligibility requirements. UMWA trustees make final interpretive determinations with regard to all benefits. The pension benefits are administered by UMWA trustees and contributions are made to their trust funds. APCo, CSPCo, I&M and OPCo administer the health and welfare benefits and pay them from their general assets. Contributions and benefits paid were not material in 2010, 2009 and 2008.
9. 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.
10. 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. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks 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 the Registrant Subsidiaries’ commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. 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 obligati ons 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 December 31, 2010 and 2009:
| | Notional Volume of Derivative Instruments |
| | December 31, 2010 |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Primary Risk | | Unit of | | | | | | | | | | | | | | | | | | |
| | Exposure | | Measure | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | | | (in thousands) |
| Commodity: | | | | | | | | | | | | | | | | | | | | |
| | Power | | MWHs | | | 194,217 | | | 111,959 | | | 117,862 | | | 136,657 | | | 21 | | | 34 |
| | Coal | | Tons | | | 11,195 | | | 5,550 | | | 6,571 | | | 23,033 | | | 4,936 | | | 8,777 |
| | Natural Gas | | MMBtus | | | 2,166 | | | 1,248 | | | 1,302 | | | 1,524 | | | 15 | | | 19 |
| | Heating Oil and | | | | | | | | | | | | | | | | | | | | |
| | | Gasoline | | Gallons | | | 1,054 | | | 467 | | | 521 | | | 776 | | | 616 | | | 564 |
| | Interest Rate | | USD | | $ | 9,541 | | $ | 5,471 | | $ | 5,732 | | $ | 7,185 | | $ | 609 | | $ | 793 |
| | | | | | | | | | | | | | | | | | | | | | | |
| Interest Rate and | | | | | | | | | | | | | | | | | | | | |
| | Foreign Currency | | USD | | $ | 200,000 | | $ | - | | $ | - | | $ | - | | $ | 200,000 | | $ | 189 |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Notional Volume of Derivative Instruments |
| | December 31, 2009 |
| | | | | | | | | | | | | | | | | | | | | | | |
| | Primary Risk | | Unit of | | | | | | | | | | | | | | | | | | |
| | Exposure | | Measure | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | | | (in thousands) |
| Commodity: | | | | | | | | | | | | | | | | | | | | |
| | Power | | MWHs | | | 191,121 | | | 96,828 | | | 99,265 | | | 112,745 | | | 10 | | | 12 |
| | Coal | | Tons | | | 11,347 | | | 5,615 | | | 5,150 | | | 23,631 | | | 5,936 | | | 6,790 |
| | Natural Gas | | MMBtus | | | 17,867 | | | 9,051 | | | 9,129 | | | 10,539 | | | - | | | - |
| | Heating Oil and | | | | | | | | | | | | | | | | | | | | |
| | | Gasoline | | Gallons | | | 1,164 | | | 474 | | | 552 | | | 838 | | | 668 | | | 628 |
| | Interest Rate | | USD | | $ | 21,054 | | $ | 10,658 | | $ | 10,716 | | $ | 13,487 | | $ | 1,137 | | $ | 1,457 |
| | | | | | | | | | | | | | | | | | | | | | | |
| Interest Rate and | | | | | | | | | | | | | | | | | | | | |
| | Foreign Currency | | USD | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | 3,798 |
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 when 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 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 nt 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 December 31, 2010 and 2009 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:
| | | | December 31, |
| | | | 2010 | | 2009 |
| | | | Cash Collateral | | Cash Collateral | | Cash Collateral | | Cash Collateral |
| | | | Received | | Paid | | Received | | Paid |
| | | | Netted Against | | Netted Against | | Netted Against | | Netted Against |
| | | | Risk Management | | Risk Management | | Risk Management | | Risk Management |
| Company | | Assets | | Liabilities | | Assets | | Liabilities |
| | | | (in thousands) |
| APCo | | $ | 1,809 | | $ | 16,229 | | $ | 3,789 | | $ | 31,806 |
| CSPCo | | | 1,042 | | | 9,347 | | | 1,920 | | | 16,108 |
| I&M | | | 1,087 | | | 9,757 | | | 1,936 | | | 16,222 |
| OPCo | | | 1,272 | | | 11,561 | | | 2,235 | | | 19,512 |
| PSO | | | - | | | 44 | | | - | | | 194 |
| SWEPCo | | | - | | | 72 | | | - | | | 305 |
The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the Balance Sheets as of December 31, 2010 and 2009:
| Fair Value of Derivative Instruments |
| December 31, 2010 |
| | | | | | | | | | | | | | | | | |
| APCo | | | | | | | | | | | | | | | |
| | | | 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 | | $ | 267,702 | | $ | 1,956 | | $ | 11,888 | | $ | (228,304) | | $ | 53,242 |
| Long-term Risk Management Assets | | | 79,560 | | | 714 | | | - | | | (41,854) | | | 38,420 |
| Total Assets | | | 347,262 | | | 2,670 | | | 11,888 | | | (270,158) | | | 91,662 |
| | | | | | | | | | | | | | | | | |
| Current Risk Management Liabilities | | | 262,027 | | | 2,363 | | | - | | | (236,397) | | | 27,993 |
| Long-term Risk Management Liabilities | | | 61,724 | | | 701 | | | - | | | (51,552) | | | 10,873 |
| Total Liabilities | | | 323,751 | | | 3,064 | | | - | | | (287,949) | | | 38,866 |
| | | | | | | | | | | | | | | | | |
| Total MTM Derivative Contract Net | | | | | | | | | | | | | | | |
| | Assets (Liabilities) | | $ | 23,511 | | $ | (394) | | $ | 11,888 | | $ | 17,791 | | $ | 52,796 |
| | | | | | | | | | | | | | | | | |
| Fair Value of Derivative Instruments |
| December 31, 2009 |
| | | | | | | | | | | | | | | | | |
| APCo | | | | | | | | | | | | | | | |
| | | | 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 | | $ | 332,764 | | $ | 3,621 | | $ | - | | $ | (268,429) | | $ | 67,956 |
| Long-term Risk Management Assets | | | 132,044 | | | - | | | - | | | (84,903) | | | 47,141 |
| Total Assets | | | 464,808 | | | 3,621 | | | - | | | (353,332) | | | 115,097 |
| | | | | | | | | | | | | | | | | |
| Current Risk Management Liabilities | | | 309,639 | | | 5,084 | | | - | | | (288,931) | | | 25,792 |
| Long-term Risk Management Liabilities | | | 118,702 | | | 80 | | | - | | | (98,418) | | | 20,364 |
| Total Liabilities | | | 428,341 | | | 5,164 | | | - | | | (387,349) | | | 46,156 |
| | | | | | | | | | | | | | | | | |
| Total MTM Derivative Contract Net | | | | | | | | | | | | | | | |
| | Assets (Liabilities) | | $ | 36,467 | | $ | (1,543) | | $ | - | | $ | 34,017 | | $ | 68,941 |
| Fair Value of Derivative Instruments |
| December 31, 2010 |
| | | | | | | | | | | | | | | | | |
| CSPCo | | | | | | | | | | | | | | | |
| | | | 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 | | $ | 149,886 | | $ | 1,164 | | $ | - | | $ | (127,276) | | $ | 23,774 |
| Long-term Risk Management Assets | | | 45,413 | | | 412 | | | - | | | (23,736) | | | 22,089 |
| Total Assets | | | 195,299 | | | 1,576 | | | - | | | (151,012) | | | 45,863 |
| | | | | | | | | | | | | | | | | |
| Current Risk Management Liabilities | | | 146,540 | | | 1,362 | | | - | | | (131,935) | | | 15,967 |
| Long-term Risk Management Liabilities | | | 35,144 | | | 404 | | | - | | | (29,325) | | | 6,223 |
| Total Liabilities | | | 181,684 | | | 1,766 | | | - | | | (161,260) | | | 22,190 |
| | | | | | | | | | | | | | | | | |
| Total MTM Derivative Contract Net | | | | | | | | | | | | | | | |
| | Assets (Liabilities) | | $ | 13,615 | | $ | (190) | | $ | - | | $ | 10,248 | | $ | 23,673 |
| | | | | | | | | | | | | | | | | |
| Fair Value of Derivative Instruments |
| December 31, 2009 |
| | | | | | | | | | | | | | | | | |
| CSPCo | | | | | | | | | | | | | | | |
| | | | 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 | | $ | 168,137 | | $ | 1,805 | | $ | - | | $ | (135,599) | | $ | 34,343 |
| Long-term Risk Management Assets | | | 66,816 | | | - | | | - | | | (42,934) | | | 23,882 |
| Total Assets | | | 234,953 | | | 1,805 | | | - | | | (178,533) | | | 58,225 |
| | | | | | | | | | | | | | | | | |
| Current Risk Management Liabilities | | | 156,463 | | | 2,574 | | | - | | | (145,985) | | | 13,052 |
| Long-term Risk Management Liabilities | | | 60,048 | | | 41 | | | - | | | (49,776) | | | 10,313 |
| Total Liabilities | | | 216,511 | | | 2,615 | | | - | | | (195,761) | | | 23,365 |
| | | | | | | | | | | | | | | | | |
| Total MTM Derivative Contract Net | | | | | | | | | | | | | | | |
| | Assets (Liabilities) | | $ | 18,442 | | $ | (810) | | $ | - | | $ | 17,228 | | $ | 34,860 |
| Fair Value of Derivative Instruments |
| December 31, 2010 |
| | | | | | | | | | | | | | | | | |
| I&M | | | | | | | | | | | | | | | |
| | | | 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 | | $ | 162,896 | | $ | 1,151 | | $ | - | | $ | (136,521) | | $ | 27,526 |
| Long-term Risk Management Assets | | | 56,154 | | | 429 | | | - | | | (25,098) | | | 31,485 |
| Total Assets | | | 219,050 | | | 1,580 | | | - | | | (161,619) | | | 59,011 |
| | | | | | | | | | | | | | | | | |
| Current Risk Management Liabilities | | | 156,750 | | | 1,421 | | | - | | | (141,386) | | | 16,785 |
| Long-term Risk Management Liabilities | | | 37,039 | | | 421 | | | - | | | (30,930) | | | 6,530 |
| Total Liabilities | | | 193,789 | | | 1,842 | | | - | | | (172,316) | | | 23,315 |
| | | | | | | | | | | | | | | | | |
| Total MTM Derivative Contract Net | | | | | | | | | | | | | | | |
| | Assets (Liabilities) | | $ | 25,261 | | $ | (262) | | $ | - | | $ | 10,697 | | $ | 35,696 |
| | | | | | | | | | | | | | | | | |
| Fair Value of Derivative Instruments |
| December 31, 2009 |
| | | | | | | | | | | | | | | | | |
| I&M | | | | | | | | | | | | | | | |
| | | | 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 | | $ | 167,847 | | $ | 1,839 | | $ | - | | $ | (135,248) | | $ | 34,438 |
| Long-term Risk Management Assets | | | 72,127 | | | - | | | - | | | (42,993) | | | 29,134 |
| Total Assets | | | 239,974 | | | 1,839 | | | - | | | (178,241) | | | 63,572 |
| | | | | | | | | | | | | | | | | |
| Current Risk Management Liabilities | | | 156,561 | | | 2,596 | | | - | | | (145,721) | | | 13,436 |
| Long-term Risk Management Liabilities | | | 60,217 | | | 41 | | | - | | | (49,872) | | | 10,386 |
| Total Liabilities | | | 216,778 | | | 2,637 | | | - | | | (195,593) | | | 23,822 |
| | | | | | | | | | | | | | | | | |
| Total MTM Derivative Contract Net | | | | | | | | | | | | | | | |
| | Assets (Liabilities) | | $ | 23,196 | | $ | (798) | | $ | - | | $ | 17,352 | | $ | 39,750 |
| Fair Value of Derivative Instruments |
| December 31, 2010 |
| | | | | | | | | | | | | | | | | |
| OPCo | | | | | | | | | | | | | | | |
| | | | 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 | | $ | 262,751 | | $ | 1,316 | | $ | - | | $ | (233,294) | | $ | 30,773 |
| Long-term Risk Management Assets | | | 63,533 | | | 503 | | | - | | | (36,024) | | | 28,012 |
| Total Assets | | | 326,284 | | | 1,819 | | | - | | | (269,318) | | | 58,785 |
| | | | | | | | | | | | | | | | | |
| Current Risk Management Liabilities | | | 259,635 | | | 1,663 | | | - | | | (239,132) | | | 22,166 |
| Long-term Risk Management Liabilities | | | 50,757 | | | 493 | | | - | | | (42,847) | | | 8,403 |
| Total Liabilities | | | 310,392 | | | 2,156 | | | - | | | (281,979) | | | 30,569 |
| | | | | | | | | | | | | | | | | |
| Total MTM Derivative Contract Net | | | | | | | | | | | | | | | |
| | Assets (Liabilities) | | $ | 15,892 | | $ | (337) | | $ | - | | $ | 12,661 | | $ | 28,216 |
| | | | | | | | | | | | | | | | | |
| Fair Value of Derivative Instruments |
| December 31, 2009 |
| | | | | | | | | | | | | | | | | |
| OPCo | | | | | | | | | | | | | | | |
| | | | 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 | | $ | 255,179 | | $ | 2,199 | | $ | - | | $ | (207,330) | | $ | 50,048 |
| Long-term Risk Management Assets | | | 88,064 | | | - | | | - | | | (60,061) | | | 28,003 |
| Total Assets | | | 343,243 | | | 2,199 | | | - | | | (267,391) | | | 78,051 |
| | | | | | | | | | | | | | | | | |
| Current Risk Management Liabilities | | | 240,877 | | | 2,998 | | | - | | | (219,484) | | | 24,391 |
| Long-term Risk Management Liabilities | | | 81,186 | | | 47 | | | - | | | (68,723) | | | 12,510 |
| Total Liabilities | | | 322,063 | | | 3,045 | | | - | | | (288,207) | | | 36,901 |
| | | | | | | | | | | | | | | | | |
| Total MTM Derivative Contract Net | | | | | | | | | | | | | | | |
| | Assets (Liabilities) | | $ | 21,180 | | $ | (846) | | $ | - | | $ | 20,816 | | $ | 41,150 |
| Fair Value of Derivative Instruments |
| December 31, 2010 |
| | | | | | | | | | | | | | | | | |
| PSO | | | | | | | | | | | | | | | |
| | | | 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 | | $ | 19,174 | | $ | 134 | | $ | 13,558 | | $ | (18,641) | | $ | 14,225 |
| Long-term Risk Management Assets | | | 1,944 | | | - | | | - | | | (1,692) | | | 252 |
| Total Assets | | | 21,118 | | | 134 | | | 13,558 | | | (20,333) | | | 14,477 |
| | | | | | | | | | | | | | | | | |
| Current Risk Management Liabilities | | | 19,607 | | | - | | | - | | | (18,685) | | | 922 |
| Long-term Risk Management Liabilities | | | 1,889 | | | - | | | - | | | (1,692) | | | 197 |
| Total Liabilities | | | 21,496 | | | - | | | - | | | (20,377) | | | 1,119 |
| | | | | | | | | | | | | | | | | |
| Total MTM Derivative Contract Net | | | | | | | | | | | | | | | |
| | Assets (Liabilities) | | $ | (378) | | $ | 134 | | $ | 13,558 | | $ | 44 | | $ | 13,358 |
| | | | | | | | | | | | | | | | | |
| Fair Value of Derivative Instruments |
| December 31, 2009 |
| | | | | | | | | | | | | | | | | |
| PSO | | | | | | | | | | | | | | | |
| | | | 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 | | $ | 14,885 | | $ | 179 | | $ | - | | $ | (12,688) | | $ | 2,376 |
| Long-term Risk Management Assets | | | 2,640 | | | - | | | - | | | (2,590) | | | 50 |
| Total Assets | | | 17,525 | | | 179 | | | - | | | (15,278) | | | 2,426 |
| | | | | | | | | | | | | | | | | |
| Current Risk Management Liabilities | | | 14,981 | | | 301 | | | - | | | (12,703) | | | 2,579 |
| Long-term Risk Management Liabilities | | | 2,913 | | | - | | | - | | | (2,769) | | | 144 |
| Total Liabilities | | | 17,894 | | | 301 | | | - | | | (15,472) | | | 2,723 |
| | | | | | | | | | | | | | | | | |
| Total MTM Derivative Contract Net | | | | | | | | | | | | | | | |
| | Assets (Liabilities) | | $ | (369) | | $ | (122) | | $ | - | | $ | 194 | | $ | (297) |
| 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) |
| | | | | | | | | | | | | | | | | |
| Fair Value of Derivative Instruments |
| December 31, 2009 |
| | | | | | | | | | | | | | | | | |
| 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 | | $ | 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 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. |
The tables below present the Registrant Subsidiaries’ activity of derivative risk management contracts for the years ended December 31, 2010 and 2009:
| | Amount of Gain (Loss) Recognized on |
| | Risk Management Contracts |
| | Year Ended December 31, 2010 |
| | |
| | Location of Gain (Loss) | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | (in thousands) |
| | Electric Generation, Transmission and | | | | | | | | | | | | | | | | | | |
| | | Distribution Revenues | | $ | 5,057 | | $ | 22,429 | | $ | 21,834 | | $ | 18,464 | | $ | 3,156 | | $ | 3,880 |
| | Sales to AEP Affiliates | | | (2,379) | | | (2,630) | | | (2,471) | | | 7,673 | | | (794) | | | (1,523) |
| | Regulatory Assets (a) | | | (372) | | | (2,591) | | | (186) | | | (3,197) | | | 46 | | | (2,902) |
| | Regulatory Liabilities (a) | | | 27,790 | | | 1,498 | | | 8,217 | | | 1,953 | | | 878 | | | 351 |
| | Total Gain (Loss) on Risk Management | | | | | | | | | | | | | | | | | | |
| | | Contracts | | $ | 30,096 | | $ | 18,706 | | $ | 27,394 | | $ | 24,893 | | $ | 3,286 | | $ | (194) |
| | | | | | | | | | | | | | | | | | | | | |
| | Amount of Gain (Loss) Recognized on |
| | Risk Management Contracts |
| | Year Ended December 31, 2009 |
| | |
| | Location of Gain (Loss) | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | (in thousands) |
| | Electric Generation, Transmission and | | | | | | | | | | | | | | | | | | |
| | | Distribution Revenues | | $ | 16,213 | | $ | 28,738 | | $ | 39,188 | | $ | 30,575 | | $ | (94) | | $ | 44 |
| | Sales to AEP Affiliates | | | (8,978) | | | (5,650) | | | (5,450) | | | (1,120) | | | 912 | | | 750 |
| | Regulatory Assets (a) | | | - | | | (10,281) | | | (5,837) | | | (11,784) | | | (331) | | | (73) |
| | Regulatory Liabilities (a) | | | 6,908 | | | (3,486) | | | (2,394) | | | (4,319) | | | (1,280) | | | 190 |
| | Total Gain (Loss) on Risk Management | | | | | | | | | | | | | | | | | | |
| | | Contracts | | $ | 14,143 | | $ | 9,321 | | $ | 25,507 | | $ | 13,352 | | $ | (793) | | $ | 911 |
| (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 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 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 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) for bot h trading 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 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.
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 Statements of Income. During December 31, 2010 and 2009, the Registrant Subsidiaries did not employ any fair value hedging strategies. During 2008, APCo employed fair value hedging strategies and recognized an immaterial loss and no hedge ineffectiveness.
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 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 Statements of Income, or in Regulatory Assets or Regulatory Liabilities on the Balance Sheets, depending on the specific nature of the risk being hedged. During 2010, 2009 and 2008, 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 Balance Sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the Statements of Income. During 2010 and 2009, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges.
The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) into Interest Expense in those periods in which hedged interest payments occur. During 2010, APCo and PSO designated interest rate derivatives as cash flow hedges. During 2009, OPCo designated interest rate derivatives as cash flow hedges. During 2008, APCo and OPCo 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 Balance Sheets into Depreciation and Amortization expense on the 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 2010 and 2009, SWEPCo designated foreign currency derivatives as cash flow hedges. During 2008, APCo, OPCo and SWEPCo designated foreign currency derivatives as cash flow hedges.
During 2009, OPCo recognized a $6 million gain in Interest Expense related to hedge ineffectiveness on interest rate derivatives designated in cash flow hedge strategies. During 2010, 2009 and 2008, hedge ineffectiveness was immaterial or nonexistent for all of the other hedge strategies disclosed above.
The following tables provide details on designated, effective cash flow hedges included in AOCI on the Balance Sheets and the reasons for changes in cash flow hedges for the years ended December 31, 2010 and 2009. All amounts in the following tables are presented net of related income taxes.
| | Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges |
| | Year Ended December 31, 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 | | | (1,450) | | | (852) | | | (901) | | | (1,106) | | | 77 | | | 69 |
| | Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | | | | | | | |
| | | from AOCI to Income Statement/within | | | | | | | | | | | | | | | | | | |
| | | Balance Sheet: | | | | | | | | | | | | | | | | | | |
| | | | Electric Generation, Transmission, and | | | | | | | | | | | | | | | | | | |
| | | | | Distribution Revenues | | | 51 | | | 112 | | | 87 | | | 117 | | | - | | | - |
| | | | Fuel and Other Consumables Used for | | | | | | | | | | | | | | | | | | |
| | | | | Electric Generation | | | - | | | - | | | - | | | (13) | | | 197 | | | - |
| | | | Purchased Electricity for Resale | | | 393 | | | 1,068 | | | 895 | | | 1,270 | | | - | | | - |
| | | | Other Operation Expense | | | (43) | | | (33) | | | (31) | | | (39) | | | (39) | | | (44) |
| | | | Maintenance Expense | | | (70) | | | (21) | | | (28) | | | (33) | | | (24) | | | (23) |
| | | | Property, Plant and Equipment | | | (71) | | | (32) | | | (36) | | | (55) | | | (45) | | | (32) |
| | | | Regulatory Assets (a) | | | 1,660 | | | - | | | 218 | | | - | | | - | | | - |
| | | | Regulatory Liabilities (a) | | | - | | | - | | | - | | | (5) | | | - | | | - |
| | Balance in AOCI as of December 31, 2010 | | $ | (273) | | $ | (134) | | $ | (178) | | $ | (230) | | $ | 88 | | $ | 82 |
| | | | | | | | | | | | | | | | | | | | | | | |
| | 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 | | | 5,042 | | | - | | | - | | | - | | | 8,813 | | | (74) |
| | Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | | | | | | | |
| | | from AOCI to Income Statement/within | | | | | | | | | | | | | | | | | | |
| | | Balance Sheet: | | | | | | | | | | | | | | | | | | |
| | | | Depreciation and Amortization | | | | | | | | | | | | | | | | | | |
| | | | | Expense | | | - | | | - | | | - | | | 4 | | | - | | | - |
| | | | Other Operation Expense | | | - | | | - | | | - | | | - | | | - | | | 21 |
| | | | Interest Expense | | | 1,625 | | | - | | | 1,007 | | | (1,363) | | | 114 | | | 828 |
| | Balance in AOCI as of December 31, 2010 | | $ | 217 | | $ | - | | $ | (8,507) | | $ | 10,813 | | $ | 8,406 | | $ | (4,272) |
| | | | | | | | | | | | | | | | | | | | | | | |
| | 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 | | | 3,592 | | | (852) | | | (901) | | | (1,106) | | | 8,890 | | | (5) |
| | Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | | | | | | | |
| | | from AOCI to Income Statement/within | | | | | | | | | | | | | | | | | | |
| | | Balance Sheet: | | | | | | | | | | | | | | | | | | |
| | | | Electric Generation, Transmission, and | | | | | | | | | | | | | | | | | | |
| | | | | Distribution Revenues | | | 51 | | | 112 | | | 87 | | | 117 | | | - | | | - |
| | | | Fuel and Other Consumables Used for | | | | | | | | | | | | | | | | | | |
| | | | | Electric Generation | | | - | | | - | | | - | | | (13) | | | 197 | | | - |
| | | | Purchased Electricity for Resale | | | 393 | | | 1,068 | | | 895 | | | 1,270 | | | - | | | - |
| | | | Other Operation Expense | | | (43) | | | (33) | | | (31) | | | (39) | | | (39) | | | (23) |
| | | | Maintenance Expense | | | (70) | | | (21) | | | (28) | | | (33) | | | (24) | | | (23) |
| | | | Depreciation and Amortization | | | | | | | | | | | | | | | | | | |
| | | | | Expense | | | - | | | - | | | - | | | 4 | | | - | | | - |
| | | | Interest Expense | | | 1,625 | | | - | | | 1,007 | | | (1,363) | | | 114 | | | 828 |
| | | | Property, Plant and Equipment | | | (71) | | | (32) | | | (36) | | | (55) | | | (45) | | | (32) |
| | | | Regulatory Assets (a) | | | 1,660 | | | - | | | 218 | | | - | | | - | | | - |
| | | | Regulatory Liabilities (a) | | | - | | | - | | | - | | | (5) | | | - | | | - |
| | Balance in AOCI as of December 31, 2010 | | $ | (56) | | $ | (134) | | $ | (8,685) | | $ | 10,583 | | $ | 8,494 | | $ | (4,190) |
| | Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges |
| | Year Ended December 31, 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 | | | (669) | | | (462) | | | (435) | | | (522) | | | 5 | | | 190 |
| | Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | | | | | | | |
| | | from AOCI to Income Statement/within | | | | | | | | | | | | | | | | | | |
| | | Balance Sheet: | | | | | | | | | | | | | | | | | | |
| | | | Electric Generation, Transmission, and | | | | | | | | | | | | | | | | | | |
| | | | | Distribution Revenues | | | (1,646) | | | (4,088) | | | (3,189) | | | (4,903) | | | - | | | - |
| | | | Fuel and Other Consumables Used for | | | | | | | | | | | | | | | | | | |
| | | | | Electric Generation | | | (95) | | | (41) | | | (50) | | | (67) | | | (49) | | | (54) |
| | | | Purchased Electricity for Resale | | | 1,093 | | | 2,708 | | | 2,142 | | | 3,274 | | | - | | | - |
| | | | Other Operation Expense | | | - | | | - | | | - | | | - | | | - | | | - |
| | | | Maintenance Expense | | | - | | | - | | | - | | | - | | | - | | | - |
| | | | Property, Plant and Equipment | | | (58) | | | (24) | | | (29) | | | (46) | | | (34) | | | (24) |
| | | | Regulatory Assets (a) | | | 4,003 | | | - | | | 481 | | | - | | | - | | | - |
| | | | Regulatory Liabilities (a) | | | (6,097) | | | - | | | (784) | | | - | | | - | | | - |
| | Balance in AOCI as of December 31, 2009 | | $ | (743) | | $ | (376) | | $ | (382) | | $ | (366) | | $ | (78) | | $ | 112 |
| | | | | | | | | | | | | | | | | | | | | | | |
| | 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 | | | (1) | | | - | | | - | | | 10,915 | | | - | | | 49 |
| | Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | | | | | | | |
| | | from AOCI to Income Statement/within | | | | | | | | | | | | | | | | | | |
| | | Balance Sheet: | | | | | | | | | | | | | | | | | | |
| | | | Depreciation and Amortization | | | | | | | | | | | | | | | | | | |
| | | | | Expense | | | - | | | - | | | (4) | | | 4 | | | - | | | - |
| | | | Interest Expense | | | 1,669 | | | - | | | 1,011 | | | (499) | | | 183 | | | 828 |
| | Balance in AOCI as of December 31, 2009 | | $ | (6,450) | | $ | - | | $ | (9,514) | | $ | 12,172 | | $ | (521) | | $ | (5,047) |
| | | | | | | | | | | | | | | | | | | | | | | |
| | 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 | | | (670) | | | (462) | | | (435) | | | 10,393 | | | 5 | | | 239 |
| | Amount of (Gain) or Loss Reclassified | | | | | | | | | | | | | | | | | | |
| | | from AOCI to Income Statement/within | | | | | | | | | | | | | | | | | | |
| | | Balance Sheet: | | | | | | | | | | | | | | | | | | |
| | | | Electric Generation, Transmission, and | | | | | | | | | | | | | | | | | | |
| | | | | Distribution Revenues | | | (1,646) | | | (4,088) | | | (3,189) | | | (4,903) | | | - | | | - |
| | | | Fuel and Other Consumables Used for | | | | | | | | | | | | | | | | | | |
| | | | | Electric Generation | | | (95) | | | (41) | | | (50) | | | (67) | | | (49) | | | (54) |
| | | | Purchased Electricity for Resale | | | 1,093 | | | 2,708 | | | 2,142 | | | 3,274 | | | - | | | - |
| | | | Other Operation Expense | | | - | | | - | | | - | | | - | | | - | | | - |
| | | | Maintenance Expense | | | - | | | - | | | - | | | - | | | - | | | - |
| | | | Depreciation and Amortization | | | | | | | | | | | | | | | | | | |
| | | | | Expense | | | - | | | - | | | (4) | | | 4 | | | - | | | - |
| | | | Interest Expense | | | 1,669 | | | - | | | 1,011 | | | (499) | | | 183 | | | 828 |
| | | | Property, Plant and Equipment | | | (58) | | | (24) | | | (29) | | | (46) | | | (34) | | | (24) |
| | | | Regulatory Assets (a) | | | 4,003 | | | - | | | 481 | | | - | | | - | | | - |
| | | | Regulatory Liabilities (a) | | | (6,097) | | | - | | | (784) | | | - | | | - | | | - |
| | Balance in AOCI as of December 31, 2009 | | $ | (7,193) | | $ | (376) | | $ | (9,896) | | $ | 11,806 | | $ | (599) | | $ | (4,935) |
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or non-current on the Balance Sheets.
The following table represents amounts of income reclassified from AOCI to net income:
| Year | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| 2008 | | $ | 975 | | $ | 736 | | $ | 1,713 | | $ | 1,528 | | $ | 183 | | $ | 284 |
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the Balance Sheets at December 31, 2010 and 2009 were:
| Impact of Cash Flow Hedges on the Registrant Subsidiaries’ |
| Balance Sheets |
| December 31, 2010 |
| |
| | | | Hedging Assets (a) | | Hedging Liabilities (a) | | AOCI Gain (Loss) Net of Tax |
| | | | | | Interest Rate | | | | Interest Rate | | | | Interest Rate |
| | | | | | and Foreign | | | | and Foreign | | | | and Foreign |
| Company | | Commodity | | Currency | | Commodity | | Currency | | Commodity | | Currency |
| | | | (in thousands) |
| APCo | | $ | 333 | | $ | 11,888 | | $ | (727) | | $ | - | | $ | (273) | | $ | 217 |
| CSPCo | | | 229 | | | - | | | (419) | | | - | | | (134) | | | - |
| I&M | | | 175 | | | - | | | (437) | | | - | | | (178) | | | (8,507) |
| OPCo | | | 174 | | | - | | | (511) | | | - | | | (230) | | | 10,813 |
| PSO | | | 134 | | | 13,558 | | | - | | | - | | | 88 | | | 8,406 |
| SWEPCo | | | 123 | | | 5 | | | - | | | - | | | 82 | | | (4,272) |
| | | | Expected to be Reclassified to | | | |
| | | | Net Income During the Next | | | |
| | | | Twelve Months | | | |
| | | | | | | | Maximum Term for |
| | | | | | Interest Rate | | Exposure to |
| | | | | | and Foreign | | Variability of Future |
| Company | | Commodity | | Currency | | Cash Flows |
| | | | (in thousands) | | (in months) |
| APCo | | $ | (280) | | $ | (1,173) | | | 41 |
| CSPCo | | | (137) | | | - | | | 41 |
| I&M | | | (184) | | | (955) | | | 41 |
| OPCo | | | (236) | | | 1,359 | | | 41 |
| PSO | | | 88 | | | 735 | | | 12 |
| SWEPCo | | | 82 | | | (829) | | | 23 |
| Impact of Cash Flow Hedges on the Registrant Subsidiaries’ |
| Balance Sheets |
| December 31, 2009 |
| |
| | | | Hedging Assets (a) | | Hedging Liabilities (a) | | AOCI Gain (Loss) Net of Tax |
| | | | | | Interest Rate | | | | Interest Rate | | | | Interest Rate |
| | | | | | and Foreign | | | | and Foreign | | | | and Foreign |
| Company | | Commodity | | Currency | | Commodity | | Currency | | Commodity | | Currency |
| | | | (in thousands) |
| APCo | | $ | 1,999 | | $ | - | | $ | (3,542) | | $ | - | | $ | (743) | | $ | (6,450) |
| CSPCo | | | 984 | | | - | | | (1,794) | | | - | | | (376) | | | - |
| I&M | | | 1,011 | | | - | | | (1,809) | | | - | | | (382) | | | (9,514) |
| OPCo | | | 1,242 | | | - | | | (2,088) | | | - | | | (366) | | | 12,172 |
| PSO | | | 178 | | | - | | | (300) | | | - | | | (78) | | | (521) |
| SWEPCo | | | 168 | | | 5 | | | - | | | (46) | | | 112 | | | (5,047) |
| | | | Expected to be Reclassified to | |
| | | | Net Income During the Next | |
| | | | Twelve Months | |
| | | | | | Interest Rate | |
| | | | | | and Foreign | |
| Company | | Commodity | | Currency | |
| | | | (in thousands) | |
| APCo | | $ | (691) | | $ | (1,301) | |
| CSPCo | | | (349) | | | - | |
| I&M | | | (358) | | | (1,007) | |
| OPCo | | | (335) | | | 1,359 | |
| PSO | | | (79) | | | (114) | |
| SWEPCo | | | 111 | | | (829) | |
| (a) | Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the 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 lure or inability to post collateral.
Collateral Triggering Events
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 represent: (a) the Registrant Subsidiaries’ aggregate fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsi diaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of December 31, 2010 and 2009:
| | | | 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 |
| | | | 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, 2010 and 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 under outstanding debt 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 represent: (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 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 December 31, 2010 and 2009:
| | | | December 31, 2010 |
| | | | Liabilities for | | | | Additional |
| | | | Contracts with Cross | | | | Settlement |
| | | | Default Provisions | | | | Liability if Cross |
| | | | Prior to Contractual | | Amount of Cash | | Default Provision |
| Company | | Netting Arrangements | | Collateral Posted | | is Triggered |
| | | | (in thousands) |
| APCo | | $ | 76,810 | | $ | 6,637 | | $ | 23,748 |
| CSPCo | | | 44,277 | | | 3,826 | | | 13,689 |
| I&M | | | 46,188 | | | 3,991 | | | 14,280 |
| OPCo | | | 54,066 | | | 4,670 | | | 16,731 |
| PSO | | | 60 | | | - | | | 28 |
| SWEPCo | | | 75 | | | - | | | 37 |
| | | | | | | | | | | |
| | | | December 31, 2009 |
| | | | Liabilities for | | | | Additional |
| | | | Contracts with Cross | | | | Settlement |
| | | | Default Provisions | | | | Liability if Cross |
| | | | Prior to Contractual | | Amount of Cash | | Default Provision |
| Company | | Netting Arrangements | | Collateral Posted | | is Triggered |
| | | | (in thousands) |
| APCo | | $ | 154,924 | | $ | 3,115 | | $ | 33,186 |
| CSPCo | | | 78,489 | | | 1,578 | | | 16,813 |
| I&M | | | 79,158 | | | 1,592 | | | 16,955 |
| OPCo | | | 91,430 | | | 1,838 | | | 19,615 |
| PSO | | | 40 | | | - | | | 40 |
| SWEPCo | | | 139 | | | - | | | 93 |
11. FAIR VALUE MEASUREMENTS
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 December 31, 2010 and 2009 are summarized in the following table:
| | | December 31, |
| | | 2010 | | 2009 |
| Company | | Book Value | | Fair Value | | Book Value | | Fair Value |
| | | (in thousands) |
| APCo | | $ | 3,561,141 | | $ | 3,878,557 | | $ | 3,477,306 | | $ | 3,699,373 |
| CSPCo | | | 1,438,830 | | | 1,571,219 | | | 1,536,393 | | | 1,616,857 |
| I&M | | | 2,004,226 | | | 2,169,520 | | | 2,077,906 | | | 2,192,854 |
| OPCo | | | 2,729,522 | | | 2,945,280 | | | 3,242,505 | | | 3,380,084 |
| PSO | | | 971,186 | | | 1,040,656 | | | 968,121 | | | 1,007,183 |
| SWEPCo | | | 1,769,520 | | | 1,931,516 | | | 1,474,153 | | | 1,554,165 |
Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal
I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. See “Nuclear Trust Funds” section of Note 1.
The following is a summary of nuclear trust fund investments at December 31, 2010 and 2009:
| | | | December 31, |
| | | | 2010 | | 2009 |
| | | | Estimated | | Gross | | Other-Than- | | Estimated | | Gross | | Other-Than- |
| | | Fair | Unrealized | Temporary | Fair | Unrealized | Temporary |
| | | Value | Gains | Impairments | Value | Gains | Impairments |
| | | | (in thousands) |
| Cash and Cash Equivalents | | $ | 20,039 | | $ | - | | $ | - | | $ | 14,412 | | $ | - | | $ | - |
| Fixed Income Securities: | | | | | | | | | | | | | | | | | | |
| | United States Government | | | 461,084 | | | 22,582 | | | (1,489) | | | 400,565 | | | 12,708 | | | (3,472) |
| | Corporate Debt | | | 59,463 | | | 3,716 | | | (1,905) | | | 57,291 | | | 4,636 | | | (2,177) |
| | State and Local Government | | | 340,786 | | | (975) | | | (340) | | | 368,930 | | | 7,924 | | | 991 |
| | Subtotal Fixed Income Securities | | 861,333 | | | 25,323 | | | (3,734) | | | 826,786 | | | 25,268 | | | (4,658) |
| Equity Securities - Domestic | | | 633,855 | | | 183,447 | | | (122,889) | | | 550,721 | | | 234,437 | | | (119,379) |
| Spent Nuclear Fuel and | | | | | | | | | | | | | | | | | | |
| | Decommissioning Trusts | | $ | 1,515,227 | | $ | 208,770 | | $ | (126,623) | | $ | 1,391,919 | | $ | 259,705 | | $ | (124,037) |
The following table provides the securities activity within the decommissioning and SNF trusts for the years ended December 31, 2010, 2009 and 2008:
| | Years Ended December 31, |
| | 2010 | | 2009 | | 2008 |
| | (in thousands) |
| Proceeds From Investment Sales | $ | 1,361,813 | | $ | 712,742 | | $ | 732,475 |
| Purchases of Investments | | 1,414,473 | | | 770,919 | | | 803,664 |
| Gross Realized Gains on Investment Sales | | 11,570 | | | 28,218 | | | 32,634 |
| Gross Realized Losses on Investment Sales | | 2,087 | | | 1,241 | | | 7,223 |
The adjusted cost of debt securities was $835 million and $801 million as of December 31, 2010 and 2009, respectively.
The fair value of debt securities held in the nuclear trust funds, summarized by contractual maturities, at December 31, 2010 was as follows:
| | Fair Value | |
| | of Debt | |
| | Securities | |
| | | | |
| | (in thousands) | |
| Within 1 year | | $ | 22,424 | |
| 1 year – 5 years | | | 305,846 | |
| 5 years – 10 years | | | 257,096 | |
| After 10 years | | | 275,967 | |
| Total | | $ | 861,333 | |
Fair Value Measurements of Financial Assets and Liabilities
For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1.
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 December 31, 2010 and 2009. 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 valuation techn iques.
| 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) (g) | $ | 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) (g) | $ | 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 |
| December 31, 2009 |
| APCo | | | | | | | | | |
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | (in thousands) |
| | | | | | | | | | | | | | | | |
| Other Cash Deposits (d) | $ | 421 | | $ | - | | $ | - | | $ | 51 | | $ | 472 |
| | | | | | | | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | | | | | |
| Risk Management Commodity Contracts (a) | | 2,344 | | | 449,406 | | | 12,866 | | | (360,248) | | | 104,368 |
| Cash Flow Hedges: | | | | | | | | | | | | | | |
| | Commodity Hedges (a) | | - | | | 3,620 | | | - | | | (1,621) | | | 1,999 |
| Dedesignated Risk Management Contracts (b) | | - | | | - | | | - | | | 8,730 | | | 8,730 |
| Total Risk Management Assets | | 2,344 | | | 453,026 | | | 12,866 | | | (353,139) | | | 115,097 |
| | | | | | | | | | | | | | | | |
| Total Assets | $ | 2,765 | | $ | 453,026 | | $ | 12,866 | | $ | (353,088) | | $ | 115,569 |
| | | | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Risk Management Liabilities | | | | | | | | | | | | | | |
| Risk Management Commodity Contracts (a) | $ | 2,648 | | $ | 422,063 | | $ | 3,438 | | $ | (388,265) | | $ | 39,884 |
| Cash Flow Hedges: | | | | | | | | | | | | | | |
| | Commodity Hedges (a) | | - | | | 5,163 | | | - | | | (1,621) | | | 3,542 |
| DETM Assignment (c) | | - | | | - | | | - | | | 2,730 | | | 2,730 |
| Total Risk Management Liabilities | $ | 2,648 | | $ | 427,226 | | $ | 3,438 | | $ | (387,156) | | $ | 46,156 |
| Assets and Liabilities Measured at Fair Value on a Recurring Basis |
| December 31, 2010 |
| CSPCo | | | | | | | | | |
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | (in thousands) |
| | | | | | | | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | | | | | |
| Risk Management Commodity Contracts (a) (g) | $ | 972 | | $ | 185,699 | | $ | 7,950 | | $ | (150,930) | | $ | 43,691 |
| Cash Flow Hedges: | | | | | | | | | | | | | | |
| | Commodity Hedges (a) | | - | | | 1,531 | | | - | | | (1,302) | | | 229 |
| Dedesignated Risk Management Contracts (b) | | - | | | - | | | - | | | 1,943 | | | 1,943 |
| Total Risk Management Assets | $ | 972 | | $ | 187,230 | | $ | 7,950 | | $ | (150,289) | | $ | 45,863 |
| | | | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Risk Management Liabilities | | | | | | | | | | | | | | |
| Risk Management Commodity Contracts (a) (g) | $ | 953 | | $ | 175,078 | | $ | 4,975 | | $ | (159,235) | | $ | 21,771 |
| Cash Flow Hedges: | | | | | | | | | | | | | | |
| | Commodity Hedges (a) | | - | | | 1,721 | | | - | | | (1,302) | | | 419 |
| Total Risk Management Liabilities | $ | 953 | | $ | 176,799 | | $ | 4,975 | | $ | (160,537) | | $ | 22,190 |
| | Assets and Liabilities Measured at Fair Value on a Recurring Basis |
| | December 31, 2009 |
| CSPCo | | | | | | | | | |
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | (in thousands) |
| | | | | | | | | | | | | | | | |
| Other Cash Deposits (d) | $ | 16,129 | | $ | - | | $ | - | | $ | 21 | | $ | 16,150 |
| | | | | | | | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | | | | | |
| Risk Management Commodity Contracts (a) | | 1,188 | | | 227,150 | | | 6,518 | | | (182,038) | | | 52,818 |
| Cash Flow Hedges: | | | | | | | | | | | | | | |
| | Commodity Hedges (a) | | - | | | 1,805 | | | - | | | (821) | | | 984 |
| Dedesignated Risk Management Contracts (b) | | - | | | - | | | - | | | 4,423 | | | 4,423 |
| Total Risk Management Assets | | 1,188 | | | 228,955 | | | 6,518 | | | (178,436) | | | 58,225 |
| | | | | | | | | | | | | | | | |
| Total Assets | $ | 17,317 | | $ | 228,955 | | $ | 6,518 | | $ | (178,415) | | $ | 74,375 |
| | | | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Risk Management Liabilities | | | | | | | | | | | | | | |
| Risk Management Commodity Contracts (a) | $ | 1,342 | | $ | 213,330 | | $ | 1,742 | | $ | (196,226) | | $ | 20,188 |
| Cash Flow Hedges: | | | | | | | | | | | | | | |
| | Commodity Hedges (a) | | - | | | 2,615 | | | - | | | (821) | | | 1,794 |
| DETM Assignment (c) | | - | | | - | | | - | | | 1,383 | | | 1,383 |
| Total Risk Management Liabilities | $ | 1,342 | | $ | 215,945 | | $ | 1,742 | | $ | (195,664) | | $ | 23,365 |
| Assets and Liabilities Measured at Fair Value on a Recurring Basis |
| December 31, 2010 |
| I&M | | | | | | | | | |
| | | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | (in thousands) |
| | | | | | | | | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | | | | | |
| Risk Management Commodity Contracts (a) (g) | $ | 1,014 | | $ | 209,031 | | $ | 8,295 | | $ | (161,531) | | $ | 56,809 |
| Cash Flow Hedges: | | | | | | | | | | | | | | |
| | Commodity Hedges (a) | | - | | | 1,533 | | | - | | | (1,358) | | | 175 |
| Dedesignated Risk Management Contracts (b) | | - | | | - | | | - | | | 2,027 | | | 2,027 |
| Total Risk Management Assets | | 1,014 | | | 210,564 | | | 8,295 | | | (160,862) | | | 59,011 |
| | | | | | | | | | | | | | | | | |
| Spent Nuclear Fuel and Decommissioning Trusts | | | | | | | | | | | | | | |
| Cash and Cash Equivalents (e) | | - | | | 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 (f) | | 633,855 | | | - | | | - | | | - | | | 633,855 |
| Total Spent Nuclear Fuel and Decommissioning Trusts | | 633,855 | | | 869,231 | | | - | | | 12,141 | | | 1,515,227 |
| | | | | | | | | | | | | | | | | |
| Total Assets | $ | 634,869 | | $ | 1,079,795 | | $ | 8,295 | | $ | (148,721) | | $ | 1,574,238 |
| | | | | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Risk Management Liabilities | | | | | | | | | | | | | | |
| Risk Management Commodity Contracts (a) (g) | $ | 994 | | $ | 186,898 | | $ | 5,187 | | $ | (170,201) | | $ | 22,878 |
| Cash Flow Hedges: | | | | | | | | | | | | | | |
| | Commodity Hedges (a) | | - | | | 1,795 | | | - | | | (1,358) | | | 437 |
| Total Risk Management Liabilities | $ | 994 | | $ | 188,693 | | $ | 5,187 | | $ | (171,559) | | $ | 23,315 |
| | | 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 |
| | December 31, 2010 |
| OPCo | | | | | | | | | | | | | | |
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | (in thousands) |
| | | | | | | | | | | | | | | | |
| Other Cash Deposits (d) | $ | 26 | | $ | - | | $ | - | | $ | - | | $ | 26 |
| | | | | | | | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | | | | | |
| Risk Management Commodity Contracts (a) (g) | | 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) (g) | $ | 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 |
| 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 |
| | December 31, 2010 |
| PSO | | | | | | | | | |
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | (in thousands) |
| | | | | | | | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | | | | | |
| Risk Management Commodity Contracts (a) (g) | $ | - | | $ | 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) (g) | $ | - | | $ | 21,498 | | $ | - | | $ | (20,379) | | $ | 1,119 |
| | 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 |
| December 31, 2010 |
| SWEPCo | | | | | | | | | |
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | (in thousands) |
| | | | | | | | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | | | | | |
| Risk Management Commodity Contracts (a) (g) | $ | - | | $ | 36,632 | | $ | 2 | | $ | (35,115) | | $ | 1,519 |
| Cash Flow Hedges: | | | | | | | | | | | | | | |
| | Commodity Hedges | | - | | | 123 | | | - | | | - | | | 123 |
| | Interest Rate/Foreign Currency Hedges | | - | | | 5 | | | - | | | - | | | 5 |
| Total Risk Management Assets | $ | - | | $ | 36,760 | | $ | 2 | | $ | (35,115) | | $ | 1,647 |
| | | | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Risk Management Liabilities | | | | | | | | | | | | | | |
| Risk Management Commodity Contracts (a) (g) | $ | - | | $ | 39,592 | | $ | - | | $ | (35,187) | | $ | 4,405 |
| | Assets and Liabilities Measured at Fair Value on a Recurring Basis |
| | December 31, 2009 |
| SWEPCo | | | | | | | | | |
| | | Level 1 | | Level 2 | | Level 3 | | Other | | Total |
| Assets: | (in thousands) |
| | | | | | | | | | | | | | | | |
| Risk Management Assets | | | | | | | | | | | | | | |
| Risk Management Commodity Contracts (a) | $ | - | | $ | 26,945 | | $ | 22 | | $ | (24,007) | | $ | 2,960 |
| Cash Flow Hedges: | | | | | | | | | | | | | | |
| | Commodity Hedges (a) | | - | | | 216 | | | - | | | (43) | | | 173 |
| Total Risk Management Assets | $ | - | | $ | 27,161 | | $ | 22 | | $ | (24,050) | | $ | 3,133 |
| | | | | | | | | | | | | | | | |
| 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 |
| (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. |
| (d) | Amounts in “Other” column primarily represent cash deposits with third parties. Level 1 amounts primarily represent investments in money market funds. |
| (e) | Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 2 amounts primarily represent investments in money market funds. |
| (f) | Amounts represent publicly traded equity securities and equity-based mutual funds. |
| (g) | Substantially comprised of power contracts for APCo, CSPCo, I&M and OPCo and coal contracts for PSO and SWEPCo. |
There have been no transfers between Level 1 and Level 2 during the year ended December 31, 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:
| Year Ended December 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) | | | 1,670 | | | 946 | | | 963 | | | 1,107 | | | 2 | | | 2 |
| Unrealized Gain (Loss) Included in Net | | | | | | | | | | | | | | | | | | |
| | Income (or Changes in Net Assets) Relating | | | | | | | | | | | | | | | | | | |
| | to Assets Still Held at the Reporting Date (a) | | | - | | | 9,601 | | | - | | | 11,713 | | | - | | | - |
| Realized and Unrealized Gains (Losses) | | | | | | | | | | | | | | | | | | |
| | Included in Other Comprehensive Income | | | - | | | - | | | - | | | - | | | - | | | - |
| Purchases, Issuances and Settlements (c) | | | (7,163) | | | (4,039) | | | (4,121) | | | (4,761) | | | (1) | | | (1) |
| Transfers into Level 3 (d) (h) | | | 1,133 | | | 614 | | | 616 | | | 719 | | | - | | | - |
| Transfers out of Level 3 (e) (h) | | | (10,999) | | | (6,332) | | | (6,558) | | | (7,646) | | | - | | | - |
| Changes in Fair Value Allocated to Regulated | | | | | | | | | | | | | | | | | | |
| | Jurisdictions (g) | | | 11,062 | | | (2,591) | | | 7,392 | | | (3,093) | | | (2) | | | (2) |
| Balance as of December 31, 2010 | | $ | 5,131 | | $ | 2,975 | | $ | 3,108 | | $ | 3,608 | | $ | 1 | | $ | 2 |
| Year Ended December 31, 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) (b) | | | (1,324) | | | (743) | | | (719) | | | (921) | | | - | | | - |
| Unrealized Gain (Loss) Included in Net | | | | | | | | | | | | | | | | | | |
| | Income (or Changes in Net Assets) Relating | | | | | | | | | | | | | | | | | | |
| | to Assets Still Held at the Reporting Date (a) | | | - | | | 4,234 | | | - | | | 4,947 | | | - | | | - |
| Realized and Unrealized Gains (Losses) | | | | | | | | | | | | | | | | | | |
| | Included in Other Comprehensive Income | | | - | | | - | | | - | | | - | | | - | | | - |
| Purchases, Issuances and Settlements (c) | | | (5,464) | | | (2,940) | | | (2,847) | | | (3,683) | | | - | | | - |
| Transfers in and/or out of Level 3 (f) | | | (500) | | | (272) | | | (263) | | | (337) | | | - | | | - |
| Changes in Fair Value Allocated to Regulated | | | | | | | | | | | | | | | | | | |
| | Jurisdictions (g) | | | 8,707 | | | - | | | 4,293 | | | - | | | 4 | | | 6 |
| Balance as of December 31, 2009 | | $ | 9,428 | | $ | 4,776 | | $ | 4,816 | | $ | 5,569 | | $ | 2 | | $ | 3 |
| | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2008 | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| Balance as of December 31, 2007 | | $ | (697) | | $ | (263) | | $ | (280) | | $ | (1,607) | | $ | (243) | | $ | (408) |
| Realized (Gain) Loss Included in Net Income | | | | | | | | | | | | | | | | | | |
| | (or Changes in Net Assets) (a) | | | 393 | | | 86 | | | 110 | | | 1,406 | | | 244 | | | 410 |
| Unrealized Gain (Loss) Included in Net | | | | | | | | | | | | | | | | | | |
| | Income (or Changes in Net Assets) Relating | | | | | | | | | | | | | | | | | | |
| | to Assets Still Held at the Reporting Date (a) | | | - | | | 1,724 | | | - | | | 2,082 | | | - | | | (1) |
| Realized and Unrealized Gains (Losses) | | | | | | | | | | | | | | | | | | |
| | Included in Other Comprehensive Income | | | - | | | - | | | - | | | - | | | - | | | - |
| Purchases, Issuances and Settlements | | | - | | | - | | | - | | | - | | | - | | | - |
| Transfers in and/or out of Level 3 (f) | | | (931) | | | (537) | | | (516) | | | (637) | | | (1) | | | (2) |
| Changes in Fair Value Allocated to Regulated | | | | | | | | | | | | | | | | | | |
| | Jurisdictions (g) | | | 9,244 | | | 3,487 | | | 5,038 | | | 4,319 | | | (2) | | | (2) |
| Balance as of December 31, 2008 | | $ | 8,009 | | $ | 4,497 | | $ | 4,352 | | $ | 5,563 | | $ | (2) | | $ | (3) |
| (a) | Included in revenues on the 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 liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. |
| (g) | Relates to the net gains (losses) of those contracts that are not reflected on the Statements of Income. These net gains (losses) are recorded as regulatory assets/liabilities. |
| (h) | Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. |
12. INCOME TAXES
The details of the Registrant Subsidiaries’ income taxes before extraordinary loss as reported are as follows:
| Year Ended December 31, 2010 | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in thousands) |
| Income Tax Expense (Credit): | | | | | | | | | | | | | | | | | | |
| | Current | | $ | (66,216) | | $ | 59,310 | | $ | 1,795 | | $ | (47,907) | | $ | (46,528) | | $ | (16,066) |
| | Deferred | | | 144,413 | | | 74,585 | | | 63,947 | | | 218,246 | | | 92,695 | | | 81,764 |
| | Deferred Investment Tax Credits | | | (3,967) | | | (2,046) | | | (2,316) | | | (882) | | | 3,933 | | | (1,484) |
| Total Income Taxes | | $ | 74,230 | | $ | 131,849 | | $ | 63,426 | | $ | 169,457 | | $ | 50,100 | | $ | 64,214 |
| | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2009 | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in thousands) |
| Income Tax Expense (Credit): | | | | | | | | | | | | | | | | | | |
| | Current | | $ | (273,084) | | $ | 14,294 | | $ | (187,911) | | $ | (215,371) | | $ | (11,338) | | $ | (6,963) |
| | Deferred | | | 322,626 | | | 131,407 | | | 271,264 | | | 382,794 | | | 56,029 | | | 28,016 |
| | Deferred Investment Tax Credits | | | (4,093) | | | (1,980) | | | (2,316) | | | (949) | | | (770) | | | (3,542) |
| Total Income Taxes | | $ | 45,449 | | $ | 143,721 | | $ | 81,037 | | $ | 166,474 | | $ | 43,921 | | $ | 17,511 |
| | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2008 | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in thousands) |
| Income Tax Expense (Credit): | | | | | | | | | | | | | | | | | | |
| | Current | | $ | (97,447) | | $ | 111,996 | | $ | 2,575 | | $ | 72,847 | | $ | (24,763) | | $ | (25,055) |
| | Deferred | | | 145,594 | | | (303) | | | 57,879 | | | 42,717 | | | 67,874 | | | 62,060 |
| | Deferred Investment Tax Credits | | | (4,209) | | | (1,954) | | | (2,196) | | | (942) | | | (834) | | | (3,964) |
| Total Income Taxes | | $ | 43,938 | | $ | 109,739 | | $ | 58,258 | | $ | 114,622 | | $ | 42,277 | | $ | 33,041 |
Shown below for each Registrant Subsidiary is a reconciliation of the difference between the amounts of federal income taxes computed by multiplying book income before income taxes by the federal statutory rate and the amount of income taxes reported.
| APCo | Years Ended December 31, |
| | 2010 | | 2009 | | 2008 |
| | (in thousands) |
| Net Income | $ | 136,668 | | $ | 155,814 | | $ | 122,863 |
| Income Taxes | | 74,230 | | | 45,449 | | | 43,938 |
| Pretax Income | $ | 210,898 | | $ | 201,263 | | $ | 166,801 |
| | | | | | | | | |
| Income Taxes on Pretax Income at Statutory Rate (35%) | $ | 73,814 | | $ | 70,442 | | $ | 58,380 |
| Increase (Decrease) in Income Taxes resulting from the following items: | | | | | | | | |
| | | Depreciation | | 18,134 | | | 11,357 | | | 9,117 |
| | | AFUDC | | (1,860) | | | (4,469) | | | (6,159) |
| | | Removal Costs | | (6,709) | | | (6,424) | | | (6,596) |
| | | Investment Tax Credits, Net | | (3,967) | | | (4,093) | | | (4,209) |
| | | State and Local Income Taxes | | (7,189) | | | (15,821) | | | (7,583) |
| | | Conservation Easement | | - | | | (5,250) | | | - |
| | | Other | | 2,007 | | | (293) | | | 988 |
| Total Income Taxes | $ | 74,230 | | $ | 45,449 | | $ | 43,938 |
| | | | | | | | | |
| Effective Income Tax Rate | | 35.2 | % | | | 22.6 | % | | | 26.3 | % |
| CSPCo | Years Ended December 31, |
| | 2010 | | 2009 | | 2008 |
| | (in thousands) |
| Net Income | $ | 230,223 | | $ | 271,661 | | $ | 237,130 |
| Income Taxes | | 131,849 | | | 143,721 | | | 109,739 |
| Pretax Income | $ | 362,072 | | $ | 415,382 | | $ | 346,869 |
| | | | | | | | | |
| Income Taxes on Pretax Income at Statutory Rate (35%) | $ | 126,725 | | $ | 145,384 | | $ | 121,404 |
| Increase (Decrease) in Income Taxes resulting from the following items: | | | | | | | | |
| | | Depreciation | | 5,641 | | | 3,775 | | | 3,659 |
| | | Investment Tax Credits, Net | | (2,046) | | | (1,980) | | | (1,954) |
| | | State and Local Income Taxes | | 2,759 | | | 2,880 | | | 964 |
| | | Parent Company Loss Benefit | | (7,136) | | | (2,986) | | | (6,663) |
| | | Other | | 5,906 | | | (3,352) | | | (7,671) |
| Total Income Taxes | $ | 131,849 | | $ | 143,721 | | $ | 109,739 |
| | | | | | | | | |
| Effective Income Tax Rate | | 36.4 | % | | | 34.6 | % | | | 31.6 | % |
| I&M | Years Ended December 31, |
| | 2010 | | 2009 | | 2008 |
| | (in thousands) |
| Net Income | $ | 126,091 | | $ | 216,310 | | $ | 131,875 |
| Income Taxes | | 63,426 | | | 81,037 | | | 58,258 |
| Pretax Income | $ | 189,517 | | $ | 297,347 | | $ | 190,133 |
| | | | | | | | | |
| Income Taxes on Pretax Income at Statutory Rate (35%) | $ | 66,331 | | $ | 104,071 | | $ | 66,547 |
| Increase (Decrease) in Income Taxes resulting from the following items: | | | | | | | | |
| | | Depreciation | | 11,419 | | | 9,550 | | | 4,971 |
| | | Nuclear Fuel Disposal Costs | | (1,655) | | | (3,249) | | | (4,381) |
| | | AFUDC | | (9,032) | | | (7,413) | | | (3,362) |
| | | Removal Costs | | (3,663) | | | (5,960) | | | (3,839) |
| | | Investment Tax Credits, Net | | (2,316) | | | (2,316) | | | (2,196) |
| | | State and Local Income Taxes | | 3,966 | | | (15,059) | | | 3,077 |
| | | Other | | (1,624) | | | 1,413 | | | (2,559) |
| Total Income Taxes | $ | 63,426 | | $ | 81,037 | | $ | 58,258 |
| | | | | | | | | |
| Effective Income Tax Rate | | 33.5 | % | | | 27.3 | % | | | 30.6 | % |
| OPCo | Years Ended December 31, |
| | 2010 | | 2009 | | 2008 |
| | (in thousands) |
| Net Income | $ | 311,393 | | $ | 308,615 | | $ | 232,455 |
| Income Taxes | | 169,457 | | | 166,474 | | | 114,622 |
| Pretax Income | $ | 480,850 | | $ | 475,089 | | $ | 347,077 |
| | | | | | | | | |
| Income Taxes on Pretax Income at Statutory Rate (35%) | $ | 168,298 | | $ | 166,281 | | $ | 121,477 |
| Increase (Decrease) in Income Taxes resulting from the following items: | | | | | | | | |
| | | Depreciation | | 5,802 | | | 5,371 | | | 4,389 |
| | | Investment Tax Credits, Net | | (882) | | | (949) | | | (942) |
| | | State and Local Income Taxes | | (1,853) | | | 4,766 | | | 2,102 |
| | | Other | | (1,908) | | | (8,995) | | | (12,404) |
| Total Income Taxes | $ | 169,457 | | $ | 166,474 | | $ | 114,622 |
| | | | | | | | | |
| Effective Income Tax Rate | | 35.2 | % | | | 35.0 | % | | | 33.0 | % |
| PSO | Years Ended December 31, |
| | 2010 | | 2009 | | 2008 |
| | (in thousands) |
| Net Income | $ | 72,787 | | $ | 75,602 | | $ | 78,484 |
| Income Taxes | | 50,100 | | | 43,921 | | | 42,277 |
| Pretax Income | $ | 122,887 | | $ | 119,523 | | $ | 120,761 |
| | | | | | | | | |
| Income Taxes on Pretax Income at Statutory Rate (35%) | $ | 43,010 | | $ | 41,833 | | $ | 42,266 |
| Increase (Decrease) in Income Taxes resulting from the following items: | | | | | | | | |
| | | Depreciation | | (166) | | | (174) | | | (502) |
| | | Investment Tax Credits, Net | | (781) | | | (770) | | | (834) |
| | | State and Local Income Taxes | | 10,307 | | | 6,025 | | | 3,845 |
| | | Other | | (2,270) | | | (2,993) | | | (2,498) |
| Total Income Taxes | $ | 50,100 | | $ | 43,921 | | $ | 42,277 |
| | | | | | | | | |
| Effective Income Tax Rate | | 40.8 | % | | | 36.7 | % | | | 35.0 | % |
| SWEPCo | Years Ended December 31, |
| | 2010 | | 2009 | | 2008 |
| | (in thousands) |
| Net Income | $ | 146,684 | | $ | 117,203 | | $ | 96,445 |
| Extraordinary Loss | | - | | | 5,325 | | | - |
| Income Taxes | | 64,214 | | | 17,511 | | | 33,041 |
| Pretax Income | $ | 210,898 | | $ | 140,039 | | $ | 129,486 |
| | | | | | | | | |
| Income Taxes on Pretax Income at Statutory Rate (35%) | $ | 73,814 | | $ | 49,014 | | $ | 45,320 |
| Increase (Decrease) in Income Taxes resulting from the following items: | | | | | | | | |
| | | Depreciation | | 1,223 | | | 1,506 | | | 502 |
| | | Depletion | | (1,506) | | | (3,150) | | | (3,158) |
| | | AFUDC | | (15,856) | | | (16,243) | | | (5,114) |
| | | Investment Tax Credits, Net | | (1,484) | | | (3,542) | | | (3,964) |
| | | State and Local Income Taxes | | (637) | | | 647 | | | 4,121 |
| | | Parent Company Loss Benefit | | - | | | (4,232) | | | - |
| | | Other | | 8,660 | | | (6,489) | | | (4,666) |
| Total Income Taxes | $ | 64,214 | | $ | 17,511 | | $ | 33,041 |
| | | | | | | | | |
| Effective Income Tax Rate | | 30.4 | % | | | 12.5 | % | | | 25.5 | % |
The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant Subsidiary.
| APCo | | December 31, |
| | | 2010 | | 2009 |
| | | (in thousands) |
| Deferred Tax Assets | | $ | 417,393 | | $ | 404,253 |
| Deferred Tax Liabilities | | | (2,103,645) | | | (1,912,843) |
| Net Deferred Tax Liabilities | | $ | (1,686,252) | | $ | (1,508,590) |
| | | | | | | |
| Property Related Temporary Differences | | $ | (1,151,667) | | $ | (1,027,656) |
| Amounts Due from Customers for Future Federal Income Taxes | | | (104,995) | | | (106,519) |
| Deferred State Income Taxes | | | (242,579) | | | (202,987) |
| Deferred Income Taxes on Other Comprehensive Loss | | | 25,859 | | | 27,060 |
| Deferred Fuel and Purchased Power | | | (129,671) | | | (126,230) |
| Accrued Pensions | | | 52,406 | | | 58,779 |
| Regulatory Assets | | | (179,686) | | | (185,880) |
| All Other, Net | | | 44,081 | | | 54,843 |
| Net Deferred Tax Liabilities | | $ | (1,686,252) | | $ | (1,508,590) |
| CSPCo | | December 31, |
| | | 2010 | | 2009 |
| | | (in thousands) |
| Deferred Tax Assets | | $ | 143,453 | | $ | 124,087 |
| Deferred Tax Liabilities | | | (761,834) | | | (682,624) |
| Net Deferred Tax Liabilities | | $ | (618,381) | | $ | (558,537) |
| | | | | | | |
| Property Related Temporary Differences | | $ | (576,649) | | $ | (493,879) |
| Amounts Due from Customers for Future Federal Income Taxes | | | (1,013) | | | (3,182) |
| Deferred State Income Taxes | | | (7,251) | | | (9,161) |
| Deferred Income Taxes on Other Comprehensive Loss | | | 27,642 | | | 26,920 |
| Accrued Pensions | | | 6,927 | | | 8,140 |
| Regulatory Assets | | | (78,623) | | | (74,298) |
| All Other, Net | | | 10,586 | | | (13,077) |
| Net Deferred Tax Liabilities | | $ | (618,381) | | $ | (558,537) |
| I&M | | December 31, |
| | | 2010 | | 2009 |
| | | (in thousands) |
| Deferred Tax Assets | | $ | 751,455 | | $ | 722,974 |
| Deferred Tax Liabilities | | | (1,530,993) | | | (1,428,710) |
| Net Deferred Tax Liabilities | | $ | (779,538) | | $ | (705,736) |
| | | | | | | |
| Property Related Temporary Differences | | $ | (246,395) | | $ | (224,113) |
| Amounts Due from Customers for Future Federal Income Taxes | | | (27,932) | | | (25,573) |
| Deferred State Income Taxes | | | (79,522) | | | (80,345) |
| Deferred Income Taxes on Other Comprehensive Loss | | | 11,248 | | | 11,685 |
| Accrued Nuclear Decommissioning Expense | | | (394,441) | | | (354,534) |
| Post Retirement Benefits | | | 41,727 | | | 34,236 |
| Accrued Pensions | | | 36,564 | | | 49,086 |
| Regulatory Assets | | | (108,842) | | | (102,247) |
| All Other, Net | | | (11,945) | | | (13,931) |
| Net Deferred Tax Liabilities | | $ | (779,538) | | $ | (705,736) |
| OPCo | | December 31, |
| | | 2010 | | 2009 |
| | | (in thousands) |
| Deferred Tax Assets | | $ | 290,613 | | $ | 270,381 |
| Deferred Tax Liabilities | | | (1,841,019) | | | (1,601,472) |
| Net Deferred Tax Liabilities | | $ | (1,550,406) | | $ | (1,331,091) |
| | | | | | | |
| Property Related Temporary Differences | | $ | (1,263,137) | | $ | (1,127,166) |
| Amounts Due from Customers for Future Federal Income Taxes | | | (56,506) | | | (53,651) |
| Deferred State Income Taxes | | | (99,508) | | | (88,489) |
| Deferred Income Taxes on Other Comprehensive Loss | | | 69,364 | | | 63,785 |
| Deferred Fuel and Purchased Power | | | (177,057) | | | (109,204) |
| Accrued Pensions | | | (8,852) | | | 3,602 |
| Regulatory Assets | | | (71,219) | | | (74,769) |
| All Other, Net | | | 56,509 | | | 54,801 |
| Net Deferred Tax Liabilities | | $ | (1,550,406) | | $ | (1,331,091) |
| PSO | | December 31, |
| | | 2010 | | 2009 |
| | | (in thousands) |
| Deferred Tax Assets | | $ | 90,750 | | $ | 101,346 |
| Deferred Tax Liabilities | | | (751,592) | | | (663,779) |
| Net Deferred Tax Liabilities | | $ | (660,842) | | $ | (562,433) |
| | | | | | | |
| Property Related Temporary Differences | | $ | (561,364) | | $ | (500,832) |
| Amounts Due from Customers for Future Federal Income Taxes | | | (242) | | | 1,901 |
| Deferred State Income Taxes | | | (76,254) | | | (60,408) |
| Deferred Income Taxes on Other Comprehensive Loss | | | (4,574) | | | 322 |
| Accrued Pensions | | | 18,389 | | | 23,382 |
| Regulatory Assets | | | (74,404) | | | (75,101) |
| All Other, Net | | | 37,607 | | | 48,303 |
| Net Deferred Tax Liabilities | | $ | (660,842) | | $ | (562,433) |
| SWEPCo | | December 31, |
| | | 2010 | | 2009 |
| | | (in thousands) |
| Deferred Tax Assets | | $ | 104,444 | | $ | 89,938 |
| Deferred Tax Liabilities | | | (713,248) | | | (562,054) |
| Net Deferred Tax Liabilities | | $ | (608,804) | | $ | (472,116) |
| | | | | | | |
| Property Related Temporary Differences | | $ | (521,210) | | $ | (422,726) |
| Amounts Due from Customers for Future Federal Income Taxes | | | (25,800) | | | (13,927) |
| Deferred State Income Taxes | | | (56,315) | | | (32,260) |
| Deferred Income Taxes on Other Comprehensive Loss | | | 6,726 | | | 6,995 |
| Accrued Pensions | | | 9,821 | | | 20,581 |
| Regulatory Assets | | | (41,956) | | | (52,894) |
| All Other, Net | | | 19,930 | | | 22,115 |
| Net Deferred Tax Liabilities | | $ | (608,804) | | $ | (472,116) |
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. The years 2007 and 2008 are currently under examination. 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.
APCo, I&M, OPCo and PSO sustained federal, state and local net income tax operating losses in 2009 driven primarily by bonus depreciation, a change in tax accounting method related to units of property and other book versus tax temporary differences. As a result, these registrant subsidiaries accrued current federal, state and local income tax benefits in 2009. These registrant subsidiaries realized the federal cash flow benefit in 2010 as there was sufficient capacity in prior periods to carry the consolidated federal net operating loss back. Most of the registrant subsidiaries’ state and local jurisdictions do not provide for a net operating loss carry back. It is anticipated that future taxable income will be sufficient to realize the tax benefit. As such, management has determined that a valuation allowance is unnecessary.
The Registrant Subsidiaries recognize interest accruals related to uncertain tax positions in interest income or expense as applicable and penalties in Other Operation in accordance with the accounting guidance for “Income Taxes.”
The following tables show amounts reported for interest expense, interest income and reversal of prior period interest expense:
| | | | Years Ended December 31, |
| | | | 2010 | | 2009 |
| | | | | | | | Reversal of | | | | | | Reversal of |
| | | | | | | | Prior Period | | | | | | Prior Period |
| | | | Interest | | Interest | | Interest | | Interest | | Interest | | Interest |
| Company | | Expense | | Income | | Expense | | Expense | | Income | | Expense |
| | | (in thousands) |
| | APCo | | $ | 2,330 | | $ | - | | $ | 1,146 | | $ | 593 | | $ | - | | $ | 1,803 |
| | CSPCo | | | 1,549 | | | - | | | 39 | | | 1,091 | | | - | | | 200 |
| | I&M | | | - | | | 209 | | | 159 | | | - | | | 4,090 | | | 119 |
| | OPCo | | | 2,399 | | | - | | | 1,614 | | | 2,221 | | | - | | | 1,495 |
| | PSO | | | 455 | | | - | | | 871 | | | - | | | 721 | | | 382 |
| | SWEPCo | | | 749 | | | - | | | 320 | | | 12 | | | 424 | | | 428 |
| | | Year Ended December 31, 2008 |
| | | | | | | Reversal of |
| | | | | | | | | Prior Period |
| | | Interest | | Interest | | Interest |
| Company | | Expense | | Income | | Expense |
| | | (in thousands) |
| APCo | | $ | 2,365 | | $ | 5,367 | | $ | 2,635 |
| CSPCo | | | 153 | | | 3,304 | | | 3,411 |
| I&M | | | 179 | | | 1,371 | | | 5,650 |
| OPCo | | | 4,093 | | | 5,755 | | | 295 |
| PSO | | | 2,008 | | | - | | | - |
| SWEPCo | | | 1,340 | | | 1,585 | | | - |
The following table shows balances for amounts accrued for the receipt of interest:
| | | December 31, |
| Company | | 2010 | | 2009 |
| | | (in thousands) |
| APCo | | $ | 934 | | $ | 2,187 |
| CSPCo | | | 2,784 | | | 2,281 |
| I&M | | | 7,642 | | | 5,764 |
| OPCo | | | 6 | | | 1,339 |
| PSO | | | - | | | 1,735 |
| SWEPCo | | | 957 | | | 1,262 |
The following table shows balances for amounts accrued for the payment of interest and penalties:
| | | December 31, |
| Company | | 2010 | | 2009 |
| | | (in thousands) |
| APCo | | $ | 1,274 | | $ | 1,733 |
| CSPCo | | | 2,219 | | | 206 |
| I&M | | | 1,823 | | | 439 |
| OPCo | | | 3,858 | | | 4,411 |
| PSO | | | 877 | | | 3,028 |
| SWEPCo | | | 1,107 | | | 983 |
The reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:
| | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in thousands) |
| Balance at January 1, 2010 | $ | 17,292 | | $ | 16,738 | | $ | 20,007 | | $ | 48,813 | | $ | 12,216 | | $ | 10,163 |
| Increase - Tax Positions Taken During | | | | | | | | | | | | | | | | | |
| | a Prior Period | | 4,177 | | | 10,110 | | | 4,964 | | | 9,104 | | | 151 | | | 6,128 |
| Decrease - Tax Positions Taken During | | | | | | | | | | | | | | | | | |
| | a Prior Period | | (6,376) | | | (1,496) | | | (5,287) | | | (7,341) | | | (1,200) | | | (376) |
| Decrease - Tax Positions Taken During | | | | | | | | | | | | | | | | | |
| | the Current Year | | (1,015) | | | (597) | | | (1,487) | | | (1,152) | | | (517) | | | (691) |
| Decrease - Settlements with Taxing | | | | | | | | | | | | | | | | | |
| | Authorities | | (811) | | | - | | | (236) | | | (70) | | | (265) | | | (4) |
| Decrease - Lapse of the Applicable | | | | | | | | | | | | | | | | | |
| | Statute of Limitations | | - | | | - | | | (90) | | | (5,454) | | | (540) | | | (810) |
| Balance at December 31, 2010 | $ | 13,267 | | $ | 24,755 | | $ | 17,871 | | $ | 43,900 | | $ | 9,845 | | $ | 14,410 |
| | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in thousands) |
| Balance at January 1, 2009 | $ | 20,573 | | $ | 21,179 | | $ | 11,815 | | $ | 52,338 | | $ | 13,310 | | $ | 10,252 |
| Increase - Tax Positions Taken During | | | | | | | | | | | | | | | | | |
| | a Prior Period | | 5,339 | | | 6,068 | | | 8,336 | | | 11,970 | | | 2,304 | | | 4,102 |
| Decrease - Tax Positions Taken During | | | | | | | | | | | | | | | | | |
| | a Prior Period | | (8,263) | | | (9,994) | | | (14,921) | | | (14,030) | | | (2,322) | | | (3,065) |
| Increase - Tax Positions Taken During | | | | | | | | | | | | | | | | | |
| | the Current Year | | 2,471 | | | - | | | 14,398 | | | 890 | | | - | | | - |
| Decrease - Tax Positions Taken During | | | | | | | | | | | | | | | | | |
| | the Current Year | | - | | | (195) | | | - | | | - | | | (533) | | | (357) |
| Increase - Settlements with Taxing | | | | | | | | | | | | | | | | | |
| | Authorities | | - | | | - | | | 645 | | | - | | | - | | | - |
| Decrease - Lapse of the Applicable | | | | | | | | | | | | | | | | | |
| | Statute of Limitations | | (2,828) | | | (320) | | | (266) | | | (2,355) | | | (543) | | | (769) |
| Balance at December 31, 2009 | $ | 17,292 | | $ | 16,738 | | $ | 20,007 | | $ | 48,813 | | $ | 12,216 | | $ | 10,163 |
| | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | (in thousands) |
| Balance at January 1, 2008 | $ | 19,741 | | $ | 19,753 | | $ | 11,317 | | $ | 51,982 | | $ | 14,105 | | $ | 6,610 |
| Increase - Tax Positions Taken During | | | | | | | | | | | | | | | | | |
| | a Prior Period | | 1,617 | | | 1,198 | | | 100 | | | 3,133 | | | 1,322 | | | 2,233 |
| Decrease - Tax Positions Taken During | | | | | | | | | | | | | | | | | |
| | a Prior Period | | (486) | | | (1,207) | | | (2,976) | | | (2,692) | | | (6,383) | | | (2,271) |
| Increase - Tax Positions Taken During | | | | | | | | | | | | | | | | | |
| | the Current Year | | 2,891 | | | 1,575 | | | 3,335 | | | 2,446 | | | 4,806 | | | 4,193 |
| Decrease - Tax Positions Taken During | | | | | | | | | | | | | | | | | |
| | the Current Year | | (1,931) | | | (311) | | | (436) | | | (835) | | | (540) | | | (395) |
| Increase - Settlements with Taxing | | | | | | | | | | | | | | | | | |
| | Authorities | | 906 | | | 171 | | | 745 | | | 192 | | | - | | | - |
| Decrease - Settlements with Taxing | | | | | | | | | | | | | | | | | |
| | Authorities | | - | | | - | | | - | | | - | | | - | | | (28) |
| Decrease - Lapse of the Applicable | | | | | | | | | | | | | | | | | |
| | Statute of Limitations | | (2,165) | | | - | | | (270) | | | (1,888) | | | - | | | (90) |
| Balance at December 31, 2008 | $ | 20,573 | | $ | 21,179 | | $ | 11,815 | | $ | 52,338 | | $ | 13,310 | | $ | 10,252 |
Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date. The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for each Registrant Subsidiary was as follows:
| Company | | 2010 | | 2009 | | 2008 |
| | | (in thousands) |
| APCo | | $ | 1,109 | | $ | 3,777 | | $ | 5,738 |
| CSPCo | | | 10,626 | | | 9,709 | | | 11,954 |
| I&M | | | 1,664 | | | 1,271 | | | 6,283 |
| OPCo | | | 18,123 | | | 23,795 | | | 27,307 |
| PSO | | | 1,977 | | | 2,985 | | | 2,974 |
| SWEPCo | | | 2,481 | | | 2,278 | | | 2,205 |
Federal Tax Legislation – Affecting APCo
Under the Energy Tax Incentives Act of 2005, AEP filed applications with the United States Department of Energy and the IRS in 2008 for the West Virginia IGCC project and in July 2008 the IRS allocated the project $134 million in credits. In September 2008, AEP entered into a memorandum of understanding with the IRS concerning the requirements of claiming the credits. AEP had until July 2010 to meet certain minimum requirements under the agreement with the IRS or the credits would be forfeited. In July 2010, AEP forfeited the allocated tax credits.
Federal Tax Legislation – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo
The Economic Stimulus Act of 2008 provided enhanced expensing provisions for certain assets placed in service in 2008 and a 50% bonus depreciation provision similar to the one in effect in 2003 through 2004 for assets placed in service in 2008. The enacted provisions did not have a material impact on net income or financial condition, but provided a material favorable cash flow benefit for each Registrant Subsidiary as follows:
| Company | | (in thousands) |
| | | | |
| APCo | | $ | 37,831 |
| CSPCo | | | 16,776 |
| I&M | | | 21,830 |
| OPCo | | | 37,696 |
| PSO | | | 6,838 |
| SWEPCo | | | 25,872 |
The American Recovery and Reinvestment Act of 2009 provided for several new grant programs and expanded tax credits and an extension of the 50% bonus depreciation provision enacted in the Economic Stimulus Act of 2008. The enacted provisions did not have a material impact on net income or financial condition. However, the bonus depreciation contributed to AEP’s 2009 federal net operating tax loss that resulted in a 2010 cash flow benefit to the Registrant Subsidiaries as follows:
| Company | | (in thousands) |
| | | | |
| APCo | | $ | 170,466 |
| CSPCo | | | 3,192 |
| I&M | | | 78,456 |
| OPCo | | | 137,919 |
| PSO | | | 10,741 |
| 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 year ended December 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 the 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 provisions will not have a material impact on the Registrant Subsidiaries’ net income or financial condition but had a favorable impact on cash flows in 2010 as follows:
| Company | | (in thousands) |
| APCo | | $ | 43,379 |
| CSPCo | | | 85,180 |
| I&M | | | 49,740 |
| OPCo | | | 39,457 |
| PSO | | | - |
| SWEPCo | | | 30,269 |
State Tax Legislation – Affecting APCo, CSPCo, I&M, OPCo, PSO and SWEPCo
Under Ohio House Bill 66, in 2005, AEP reversed deferred state income tax liabilities that are not expected to reverse during the phase-out as follows:
| | | Other | | | | | | | Deferred State |
| | | Regulatory | | Regulatory | | State Income | | Income Tax |
| Company | | Liabilities (a) | | Asset, Net (b) | | Tax Expense (c) | | Liabilities (d) |
| | | (in thousands) |
| APCo | | $ | - | | $ | 10,945 | | $ | 2,769 | | $ | 13,714 |
| CSPCo | | | 15,104 | | | - | | | - | | | 15,104 |
| I&M | | | - | | | 5,195 | | | - | | | 5,195 |
| OPCo | | | 41,864 | | | - | | | - | | | 41,864 |
| PSO | | | - | | | - | | | 706 | | | 706 |
| SWEPCo | | | - | | | 582 | | | 119 | | | 701 |
| (a) | The reversal of deferred state income taxes for CSPCo and OPCo was recorded as a regulatory liability pending rate-making treatment in Ohio. |
| (b) | Deferred state income tax adjustments related to those companies in which state income taxes flow through for rate-making purposes reduced the regulatory asset associated with the deferred state income tax liabilities. |
| (c) | These amounts were recorded as a reduction to Income Tax Expense. |
| (d) | Total deferred state income tax liabilities that reversed during 2005 related to Ohio law change. |
In November 2006, the PUCO ordered OPCo and CSPCo to amortize $42 million and $15 million, respectively, to income as an offset to power supply contract losses incurred by OPCo and CSPCo for sales to Ormet and as of December 31, 2008, both regulatory liabilities were fully amortized.
The Ohio legislation also imposed a new commercial activity tax at a fully phased-in rate of 0.26% on all Ohio gross receipts. The tax was phased-in over a five-year period that began July 1, 2005 at 23% of the full 0.26% rate. As a result of this tax, expenses of approximately $6 million, $5 million and $4 million each for CSPCo and OPCo were recorded in 2010, 2009 and 2008, respectively, in Taxes Other Than Income Taxes.
State Tax Legislation – Affecting APCo, CSPCo, I&M and OPCo
Michigan Senate Bill 0094 (MBT Act), effective January 1, 2008, provided a comprehensive restructuring of Michigan’s principal business tax. The law replaced the Michigan Single Business Tax. The MBT Act is composed of a new tax which will be calculated based upon two components: (a) a business income tax (BIT) imposed at a rate of 4.95% and (b) a modified gross receipts tax (GRT) imposed at a rate of 0.80%, which will collectively be referred to as the BIT/GRT tax calculation. The law also includes significant credits for engaging in Michigan-based activity.
In September 2007, House Bill 5198 amended the MBT Act to provide for a new deduction on the BIT and GRT tax returns equal to the book-tax basis difference triggered as a result of the enactment of the MBT Act. This state-only temporary difference will be deducted over a 15 year period on the MBT Act tax returns starting in 2015. Management has evaluated the impact of the MBT Act and the application of the MBT Act will not materially affect net income, cash flows or financial condition.
In March 2008, legislation was signed providing for, among other things, a reduction in the West Virginia corporate income tax rate from 8.75% to 8.5% beginning in 2009. The corporate income tax rate could also be reduced to 7.75% in 2012 and 7% in 2013 contingent upon the state government achieving certain minimum levels of shortfall reserve funds. Management has evaluated the impact of the law change and the application of the law change will not materially impact net income, cash flows or financial condition.
13. LEASES
Leases of property, plant and equipment are for periods up to 60 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.
Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows:
| Year Ended December 31, 2010 | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| Net Lease Expense on Operating Leases | | $ | 18,034 | | $ | 40,011 | | $ | 91,973 | | $ | 22,876 | | $ | 2,649 | | $ | 5,877 |
| Amortization of Capital Leases | | | 7,002 | | | 4,204 | | | 31,178 | | | 7,865 | | | 3,992 | | | 11,742 |
| Interest on Capital Leases | | | 1,598 | | | 639 | | | 2,298 | | | 2,493 | | | 1,057 | | | 9,892 |
| Total Lease Rental Costs | | $ | 26,634 | | $ | 44,854 | | $ | 125,449 | | $ | 33,234 | | $ | 7,698 | | $ | 27,511 |
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2009 | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| Net Lease Expense on Operating Leases | | $ | 21,001 | | $ | 45,124 | | $ | 94,409 | | $ | 28,334 | | $ | 5,807 | | $ | 8,052 |
| Amortization of Capital Leases | | | 3,480 | | | 2,715 | | | 31,612 | | | 4,688 | | | 1,485 | | | 10,739 |
| Interest on Capital Leases | | | 206 | | | 140 | | | 1,937 | | | 1,284 | | | 85 | | | 6,372 |
| Total Lease Rental Costs | | $ | 24,687 | | $ | 47,979 | | $ | 127,958 | | $ | 34,306 | | $ | 7,377 | | $ | 25,163 |
| | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2008 | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| Net Lease Expense on Operating Leases | | $ | 18,840 | | $ | 42,330 | | $ | 96,595 | | $ | 25,876 | | $ | 6,995 | | $ | 8,519 |
| Amortization of Capital Leases | | | 4,820 | | | 3,329 | | | 39,697 | | | 6,369 | | | 1,550 | | | 6,926 |
| Interest on Capital Leases | | | 525 | | | 482 | | | 5,311 | | | 1,606 | | | 140 | | | 3,855 |
| Total Lease Rental Costs | | $ | 24,185 | | $ | 46,141 | | $ | 141,603 | | $ | 33,851 | | $ | 8,685 | | $ | 19,300 |
The following table shows the property, plant and equipment under capital leases and related obligations recorded on the Registrant Subsidiaries’ balance sheets. For I&M, current capital lease obligations are included in Obligations Under Capital Leases on I&M’s Consolidated Balance Sheets. For all other Registrant Subsidiaries, current capital lease obligations are included in Other Current Liabilities. For all Registrant Subsidiaries, long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrant Subsidiaries’ balance sheets.
| December 31, 2010 | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| Property, Plant and Equipment Under | | | | | | | | | | | | | | | | | | |
| | Capital Leases: | | | | | | | | | | | | | | | | | | |
| Generation | | $ | 10,255 | | $ | 1,696 | | $ | 19,147 | | $ | 32,524 | | $ | 3,471 | | $ | 15,528 |
| Distribution | | | - | | | - | | | - | | | - | | | - | | | - |
| Other Property, Plant and Equipment | | | 29,154 | | | 14,144 | | | 26,922 | | | 29,965 | | | 19,256 | | | 142,210 |
| Construction Work in Progress | | | - | | | - | | | - | | | - | | | - | | | - |
| Total Property, Plant and Equipment | | | 39,409 | | | 15,840 | | | 46,069 | | | 62,489 | | | 22,727 | | | 157,738 |
| Accumulated Amortization | | | 6,678 | | | 3,953 | | | 10,366 | | | 15,010 | | | 4,338 | | | 29,370 |
| Net Property, Plant and Equipment | | | | | | | | | | | | | | | | | | |
| | Under Capital Leases | | $ | 32,731 | | $ | 11,887 | | $ | 35,703 | | $ | 47,479 | | $ | 18,389 | | $ | 128,368 |
| | | | | | | | | | | | | | | | | | | | |
| Obligations Under Capital Leases: | | | | | | | | | | | | | | | | | | |
| Noncurrent Liability | | $ | 24,617 | | $ | 7,965 | | $ | 26,858 | | $ | 38,237 | | $ | 13,838 | | $ | 115,399 |
| Liability Due Within One Year | | | 8,114 | | | 3,990 | | | 8,845 | | | 12,070 | | | 4,551 | | | 13,265 |
| | | | | | | | | | | | | | | | | | | | |
| Total Obligations Under Capital Leases | | $ | 32,731 | | $ | 11,955 | | $ | 35,703 | | $ | 50,307 | | $ | 18,389 | | $ | 128,664 |
| December 31, 2009 | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| Property, Plant and Equipment Under | | | | | | | | | | | | | | | | | | |
| | Capital Leases: | | | | | | | | | | | | | | | | | | |
| Generation | | $ | 90 | | $ | 6,989 | | $ | 16,363 | | $ | 23,018 | | $ | 2,041 | | $ | 13,869 |
| Distribution | | | - | | | - | | | - | | | - | | | - | | | - |
| Other Property, Plant and Equipment | | | 15,401 | | | 8,477 | | | 50,587 | | | 13,344 | | | 6,973 | | | 164,632 |
| Construction Work in Progress | | | - | | | - | | | - | | | - | | | - | | | - |
| Total Property, Plant and Equipment | | | 15,491 | | | 15,466 | | | 66,950 | | | 36,362 | | | 9,014 | | | 178,501 |
| Accumulated Amortization | | | 8,007 | | | 10,769 | | | 14,400 | | | 16,066 | | | 3,544 | | | 30,858 |
| Net Property, Plant and Equipment | | | | | | | | | | | | | | | | | | |
| | Under Capital Leases | | $ | 7,484 | | $ | 4,697 | | $ | 52,550 | | $ | 20,296 | | $ | 5,470 | | $ | 147,643 |
| | | | | | | | | | | | | | | | | | | | |
| Obligations Under Capital Leases: | | | | | | | | | | | | | | | | | | |
| Noncurrent Liability | | $ | 4,539 | | $ | 2,452 | | $ | 27,485 | | $ | 16,926 | | $ | 3,722 | | $ | 134,044 |
| Liability Due Within One Year | | | 2,945 | | | 2,274 | | | 25,065 | | | 5,756 | | | 1,748 | | | 14,617 |
| | | | | | | | | | | | | | | | | | | | |
| Total Obligations Under Capital Leases | | $ | 7,484 | | $ | 4,726 | | $ | 52,550 | | $ | 22,682 | | $ | 5,470 | | $ | 148,661 |
Future minimum lease payments consisted of the following at December 31, 2010:
| Capital Leases | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| 2011 | | $ | 9,529 | | $ | 4,472 | | $ | 10,345 | | $ | 11,702 | | $ | 5,448 | | $ | 22,306 |
| 2012 | | | 8,571 | | | 2,769 | | | 9,144 | | | 9,377 | | | 4,208 | | | 21,722 |
| 2013 | | | 5,901 | | | 2,379 | | | 4,702 | | | 8,902 | | | 3,610 | | | 20,540 |
| 2014 | | | 3,616 | | | 1,820 | | | 3,779 | | | 6,665 | | | 2,689 | | | 19,079 |
| 2015 | | | 2,885 | | | 695 | | | 2,742 | | | 4,773 | | | 1,475 | | | 17,053 |
| Later Years | | | 6,897 | | | 1,284 | | | 15,933 | | | 21,952 | | | 4,082 | | | 78,506 |
| Total Future Minimum Lease | | | | | | | | | | | | | | | | | | |
| | Payments | | | 37,399 | | | 13,419 | | | 46,645 | | | 63,371 | | | 21,512 | | | 179,206 |
| Less Estimated Interest Element | | | 4,668 | | | 1,464 | | | 10,942 | | | 13,064 | | | 3,123 | | | 50,542 |
| Estimated Present Value of Future | | | | | | | | | | | | | | | | | | |
| | Minimum Lease Payments | | $ | 32,731 | | $ | 11,955 | | $ | 35,703 | | $ | 50,307 | | $ | 18,389 | | $ | 128,664 |
| | | | | | | | | | | | | | | | | | | | |
| Noncancelable Operating Leases | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| 2011 | | $ | 14,339 | | $ | 38,904 | | $ | 97,750 | | $ | 20,708 | | $ | 2,281 | | $ | 6,015 |
| 2012 | | | 11,505 | | | 36,479 | | | 95,170 | | | 19,379 | | | 2,031 | | | 4,861 |
| 2013 | | | 9,939 | | | 34,911 | | | 94,612 | | | 18,978 | | | 1,464 | | | 4,199 |
| 2014 | | | 9,311 | | | 33,456 | | | 93,880 | | | 18,687 | | | 949 | | | 3,140 |
| 2015 | | | 8,332 | | | 31,920 | | | 90,786 | | | 17,408 | | | 626 | | | 2,599 |
| Later Years | | | 57,971 | | | 60,936 | | | 561,803 | | | 71,457 | | | 974 | | | 12,518 |
| Total Future Minimum Lease | | | | | | | | | | | | | | | | | | |
| | Payments | | $ | 111,397 | | $ | 236,606 | | $ | 1,034,001 | | $ | 166,617 | | $ | 8,325 | | $ | 33,332 |
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) to replace existing operating and capital leases with GE. These assets were included in existing master lease agreements that were to be terminated in 2011 since GE exercised the termination provision related to these leases in 2008. Certain assets were not included in the refinancing, but the assets will be purchased or refinanced in 2011. In addition, certain operating leases that were previously under lease with GE are now recorded as capital leases after the refinancing. The amounts refinanced for the Registrant Subsidiaries are as follows:
| Leases Refinanced with GE | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | (in thousands) |
| Operating Lease to Operating Lease | | $ | 6,815 | | $ | 8,382 | | $ | 12,245 | | $ | 7,443 | | $ | 2,458 | | $ | 13,091 |
| Capital Lease to Capital Lease | | | 1,602 | | | 965 | | | 6,749 | | | 1,491 | | | 522 | | | 652 |
| Operating Lease to Capital Lease | | | 11,252 | | | 1,906 | | | 4,984 | | | 10,087 | | | 3,205 | | | 4,574 |
These obligations are included in the future minimum lease payments schedule earlier in this note.
For equipment under the GE master lease agreements, the lessor is guaranteed receipt of up to 84% 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 84% of the unamortized balance. For 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 Subsidiari es are committed to pay the difference between the actual fair value and the residual value guarantee. At December 31, 2010, 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 | | Maximum |
| | | Potential | | Potential Loss |
| Company | | Loss | | Net of Tax |
| | | (in thousands) |
| APCo | | $ | 1,197 | | $ | 778 |
| CSPCo | | | 888 | | | 577 |
| I&M | | | 1,768 | | | 1,149 |
| OPCo | | | 1,216 | | | 790 |
| PSO | | | 616 | | | 400 |
| SWEPCo | | | 2,572 | | | 1,672 |
Historically, at the end of the lease term the fair value has been in excess of the unamortized balance.
Rockport Lease
AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors.
The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it equally to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. Neither AEGCo, I&M nor AEP has an ownership interest in the Owner Trustee and do not guarantee its debt. I&M’s future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2010 are as follows:
| Future Minimum Lease Payments | | I&M |
| | | | (in millions) |
| 2011 | | $ | 74 |
| 2012 | | | 74 |
| 2013 | | | 74 |
| 2014 | | | 74 |
| 2015 | | | 74 |
| Later Years | | | 517 |
| Total Future Minimum Lease Payments | | $ | 887 |
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 $17 million for I&M and $19 million for SWEPCo for the remaining railcars as of December 31, 2010. These obligations are included in the future minimum lease payments schedule earlier in this note.
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, management believes that the fair value would produc e a sufficient sales price to avoid any loss.
Sabine Dragline Lease
During 2009, Sabine, an entity consolidated in accordance with the accounting guidance for “Variable Interest Entities,” entered into capital lease arrangements with a nonaffiliated company to finance the purchase of two electric draglines to be used for Sabine’s mining operations totaling $47 million. The amounts included in the lease represented the aggregate fair value of the existing equipment and a sale and leaseback transaction for additional dragline rebuild costs required to keep the dragline operational. In addition to the 2009 transactions, Sabine has one additional $53 million dragline completed in 2008 that was financed under a capital lease. These capital lease assets are included in Other Property, Plant and Equipment on SWEPCo’s December 31, 2010 and 2009 Consoli dated Balance Sheets. The short-term and long-term capital lease obligations are included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on SWEPCo’s December 31, 2010 and 2009 Consolidated Balance Sheets. The future payment obligations are included in SWEPCo’s future minimum lease payments schedule earlier in this note.
I&M Nuclear Fuel Lease
In December 2007, I&M entered into a sale-and-leaseback transaction with Citicorp Leasing, Inc. (CLI), an unrelated, unconsolidated, wholly-owned subsidiary of Citibank, N.A. to lease nuclear fuel for I&M’s Cook Plant. In December 2007, I&M sold a portion of its unamortized nuclear fuel inventory to CLI at cost for $85 million. The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 60 months. The future payment obligations of $3 million are included in I&M’s future minimum lease payments schedule earlier in this note. The net capital lease asset is included in Other Property, Plant and Equipment and the short-term and long-term capital lease obligations are included in Other Current Liabilities and De ferred Credits and Other Noncurrent Liabilities, respectively, on I&M’s December 31, 2010 and 2009 Consolidated Balance Sheets. The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2010 are as follows, based on estimated fuel burn:
| Future Minimum Lease Payments | | Amount |
| | | (in millions) |
| 2011 | | $ | 2 |
| 2012 | | | 1 |
| Total Future Minimum Lease Payments | | $ | 3 |
14. FINANCING ACTIVITIES
Preferred Stock
| | | | | | | | Shares | | | | | | | | | | | | | | |
| | | | | | | | Outstanding at | | Call Price at | | | | | | | | | | | |
| | | Par | | Authorized | | December 31, | | December 31, | | | | | | | | December 31, |
| Company | | Value | | Shares | | 2010 | | 2010 (a) | | Series | | Redemption | | 2010 | | 2009 |
| | | | | | | | | | | | | | | | | | (in thousands) |
| APCo | | $ | - | (b) | 8,000,000 | | 177,465 | | $ | 110.00 | | 4.50 | % | | Any time | | $ | 17,747 | | $ | 17,752 |
| CSPCo | | | 25 | | 7,000,000 | | - | | | - | | - | | | - | | | - | | | - |
| CSPCo | | | 100 | | 2,500,000 | | - | | | - | | - | | | - | | | - | | | - |
| I&M | | | 25 | | 11,200,000 | | - | | | - | | - | | | - | | | - | | | - |
| I&M | | | 100 | | (c) | | 55,257 | | | 106.13 | | 4.125 | % | | Any time | | | 5,525 | | | 5,530 |
| I&M | | | 100 | | (c) | | 14,412 | | | 102.00 | | 4.56 | % | | Any time | | | 1,441 | | | 1,441 |
| I&M | | | 100 | | (c) | | 11,055 | | | 102.73 | | 4.12 | % | | Any time | | | 1,106 | | | 1,106 |
| OPCo | | | 25 | | 4,000,000 | | - | | | - | | - | | | - | | | - | | | - |
| OPCo | | | 100 | | (d) | | 14,495 | | | 103.00 | | 4.08 | % | | Any time | | | 1,450 | | | 1,460 |
| OPCo | | | 100 | | (d) | | 22,824 | | | 103.20 | | 4.20 | % | | Any time | | | 2,282 | | | 2,282 |
| OPCo | | | 100 | | (d) | | 31,482 | | | 104.00 | | 4.40 | % | | Any time | | | 3,148 | | | 3,148 |
| OPCo | | | 100 | | (d) | | 97,357 | | | 110.00 | | 4.50 | % | | Any time | | | 9,736 | | | 9,737 |
| PSO | | | 100 | | (e) | | 44,508 | | | 105.75 | | 4.00 | % | | Any time | | | 4,451 | | | 4,451 |
| PSO | | | 100 | | (e) | | 4,310 | | | 103.19 | | 4.24 | % | | Any time | | | 431 | | | 807 |
| SWEPCo | | | 100 | | (f) | | 7,386 | | | 103.90 | | 4.28 | % | | Any time | | | 739 | | | 740 |
| SWEPCo | | | 100 | | (f) | | 1,907 | | | 102.75 | | 4.65 | % | | Any time | | | 190 | | | 190 |
| SWEPCo | | | 100 | | (f) | | 37,665 | | | 109.00 | | 5.00 | % | | Any time | | | 3,767 | | | 3,767 |
| | (a) | The cumulative preferred stock is callable at the price indicated plus accrued dividends. If the Registrant Subsidiary defaults on preferred stock dividend payments for a period of one year or longer, preferred stock holders are entitled, voting separately as one class, to elect the number of directors necessary to constitute a majority of the Registrant Subsidiary’s full board of directors. |
| | (b) | Stated value is $100 per share. |
| | (c) | I&M has 2,250,000 authorized $100 par value per share shares in total. |
| | (d) | OPCo has 3,762,403 authorized $100 par value per share shares in total. |
| | (e) | PSO has 700,000 authorized shares in total. |
| | (f) | SWEPCo has 1,860,000 authorized shares in total. |
| | | | | | | Number of Shares Redeemed for the |
| | | | | | | Years Ended December 31, |
| Company | | Series | | 2010 | | 2009 | | 2008 |
| APCo | | 4.50 | % | | 53 | | 2 | | - |
| I&M | | 4.125 | % | | 44 | | 34 | | - |
| OPCo | | 4.08 | % | | 100 | | - | | - |
| OPCo | | 4.50 | % | | 6 | | 10 | | - |
| PSO | | 4.00 | % | | - | | 40 | | - |
| PSO | | 4.24 | % | | 3,759 | | - | | - |
| SWEPCo | | 5.00 | % | | 8 | | - | | - |
Long-term Debt
There are certain limitations on establishing liens against the Registrant Subsidiaries’ assets under their respective indentures. None of the long-term debt obligations of the Registrant Subsidiaries have been guaranteed or secured by AEP or any of its affiliates.
The following details long-term debt outstanding as of December 31, 2010 and 2009:
| | | | | Weighted | | | | |
| | | | | Average | | | | |
| | | | | Interest | | | | | | | | | | |
| | | | | Rate at | | | | Outstanding at |
| | | | | December 31, | | Interest Rate Ranges at December 31, | | December 31, |
| Company | | Maturity | | 2010 | | 2010 | | 2009 | | 2010 | | 2009 |
| Senior Unsecured Notes | | | | | | | | | | (in thousands) |
| APCo | | 2010-2038 | | 5.98% | | 3.40%-7.95% | | 4.40%-7.95% | | $ | 3,042,060 | | $ | 2,875,885 |
| CSPCo | | 2010-2035 | | 5.37% | | 0.702%-6.60% | | 4.40%-6.60% | | | 1,246,085 | | | 1,243,648 |
| I&M | | 2012-2037 | | 6.25% | | 5.05%-7.00% | | 5.05%-7.00% | | | 1,270,116 | | | 1,419,633 |
| OPCo | | 2010-2033 | | 5.74% | | 4.85%-6.60% | | 0.4644%-6.60% | | | 2,044,942 | | | 2,643,925 |
| PSO | | 2011-2037 | | 5.86% | | 4.70%-6.625% | | 4.70%-6.625% | | | 922,576 | | | 921,761 |
| SWEPCo | | 2015-2040 | | 5.92% | | 4.90%-6.45% | | 4.90%-6.45% | | | 1,548,185 | | | 1,196,944 |
| | | | | | | | | | | | | | | |
| Pollution Control Bonds (a) | | | | | | | | | | | | | | |
| APCo | | 2010-2042 (b) | 3.09% | | 0.29%-6.05% | | 0.20%-7.125% | | | 516,650 | | | 498,972 |
| CSPCo | | 2012-2038 (b) | 4.78% | | 3.875%-5.80% | | 3.875%-5.80% | | | 192,745 | | | 192,745 |
| I&M | | 2011-2025 (b) | 4.09% | | 0.33%-6.25% | | 0.23%-6.25% | | | 266,456 | | | 266,418 |
| OPCo | | 2010-2037 (b) | 2.62% | | 0.30%-5.15% | | 0.22%-7.125% | | | 484,580 | | | 398,580 |
| PSO | | 2014-2020 | | 5.03% | | 4.45%-5.25% | | 4.45%-5.25% | | | 46,360 | | | 46,360 |
| SWEPCo | | 2011-2019 (b) | 4.33% | | 3.25%-4.95% | | 0.82%-4.95% | | | 176,335 | | | 176,335 |
| | | | | | | | | | | | | | | |
| Notes Payable - Affiliated | | | | | | | | | | | | | | |
| APCo | | 2010 | | - | | - | | 4.708% | | | - | | | 100,000 |
| CSPCo | | 2010 | | - | | - | | 4.64% | | | - | | | 100,000 |
| I&M | | 2010 | | - | | - | | 5.375% | | | - | | | 25,000 |
| OPCo | | 2015 | | 5.25% | | 5.25% | | 5.25% | | | 200,000 | | | 200,000 |
| SWEPCo | | 2010 | | - | | - | | 4.45% | | | - | | | 50,000 |
| | | | | | | | | | | | | | | |
| Notes Payable - Nonaffiliated | | | | | | | | | | | | | | |
| I&M | | 2013-2015 | | 3.81% | | 2.07%-5.44% | | 5.44% | | | 202,753 | | | 102,300 |
| SWEPCo | | 2012-2024 | | 6.66% | | 6.37%-7.03% | | 4.47%-7.03% | | | 45,000 | | | 50,874 |
| | | | | | | | | | | | | | | |
| Spent Nuclear Fuel Liability (c) | | | | | | | | | | | | | |
| I&M | | | | | | | | | | | 264,901 | | | 264,555 |
| | | | | | | | | | | | | | | |
| Other Long-term Debt | | | | | | | | | | | | | | |
| APCo | | 2026 | | 13.718% | | 13.718% | | 13.718% | | | 2,431 | | | 2,449 |
| PSO | | 2026 | | 3.00% | | 3.00% | | - | | | 2,250 | | | - |
| (a) | For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks, standby bond purchase agreements and insurance policies support certain series. |
| (b) | Certain pollution control bonds are subject to mandatory redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity and repayment purposes based on the mandatory redemption date. |
| (c) | Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6). |
At December 31, 2010, $50 million of PSO’s Senior Unsecured Notes, which are due within one year, are classified as long-term debt due to management’s intent and ability to refinance these notes on a long-term basis. In January 2011, PSO issued $250 million of 4.4% Senior Unsecured Notes due in 2021, demonstrating the ability to refinance these obligations on a long-term basis.
At December 31, 2009, approximately $230 million, $77 million and $165 million of variable-rate, tax-exempt bonds were outstanding for APCo, I&M and OPCo, respectively. These bonds, which are short-term obligations, were classified as long-term debt due to management’s intent and ability to refinance each obligation on a long-term basis. At December 31, 2009, the $478 million credit facility had non-cancelable terms in excess of one year, demonstrating the ability to refinance these short-term obligations on a long-term basis.
Long-term debt outstanding at December 31, 2010 is payable as follows:
| | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| 2011 | $ | 479,672 | | $ | - | | $ | 154,457 | | $ | 165,000 | | $ | 25,000 | | $ | 41,135 |
| 2012 | | 250,025 | | | 194,500 | | | 161,389 | | | - | | | 150 | | | 20,000 |
| 2013 | | 70,029 | | | 306,000 | | | 43,937 | | | 500,000 | | | 150 | | | - |
| 2014 | | 33 | | | 60,000 | | | 290,943 | | | 343,580 | | | 33,850 | | | - |
| 2015 | | 500,038 | | | - | | | 129,027 | | | 286,000 | | | 150 | | | 303,500 |
| After 2015 | | 2,269,284 | | | 882,245 | | | 1,229,901 | | | 1,440,000 | | | 914,310 | | | 1,406,700 |
| Total Principal Amount | | 3,569,081 | | | 1,442,745 | | | 2,009,654 | | | 2,734,580 | | | 973,610 | | | 1,771,335 |
| Unamortized Discount | | (7,940) | | | (3,915) | | | (5,428) | | | (5,058) | | | (2,424) | | | (1,815) |
| Total Long-term Debt | | | | | | | | | | | | | | | | | |
| | Outstanding | $ | 3,561,141 | | $ | 1,438,830 | | $ | 2,004,226 | | $ | 2,729,522 | | $ | 971,186 | | $ | 1,769,520 |
In February 2011, APCo issued $65 million of 2% Pollution Control Bonds due in 2041 with a 2012 mandatory put date.
On behalf of OPCo, trustees held $303 million of reacquired variable rate tax-exempt long-term debt as of December 31, 2010.
Dividend Restrictions
The Registrant Subsidiaries pay dividends to 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 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 December 31, 2010, approximately $150 million of the retained earnings of APCo, $77 million of the retained earnings of CSPCo, $101 million of the retained earnings of SWEPCo and none of the retained earnings of I&M, OPCo and 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 December 31, 2010 and 2009 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 years ended December 31, 2010 and 2009 are described in the following tables:
Year Ended December 31, 2010:
| | | | | | | | | | | | 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 | | December 31, 2010 | | Limit |
| | | (in thousands) |
| APCo | | $ | 438,039 | | $ | - | | $ | 227,002 | | $ | - | | $ | (128,331) | | $ | 600,000 |
| CSPCo | | | 134,592 | | | 229,758 | | | 32,368 | | | 96,009 | | | 54,202 | | | 350,000 |
| I&M | | | 42,769 | | | 223,111 | | | 17,972 | | | 107,123 | | | (42,769) | | | 500,000 |
| OPCo | | | - | | | 618,559 | | | - | | | 231,600 | | | 100,500 | | | 600,000 |
| PSO | | | 107,320 | | | 74,751 | | | 45,287 | | | 31,211 | | | (91,382) | | | 300,000 |
| SWEPCo | | | 78,616 | | | 274,958 | | | 39,458 | | | 184,126 | | | 86,222 | | | 350,000 |
Year Ended December 31, 2009:
| | | | | | | | | | | | 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 | | December 31, 2009 | | Limit |
| | | (in thousands) |
| APCo | | $ | 420,925 | | $ | - | | $ | 207,121 | | $ | - | | $ | (229,546) | | $ | 600,000 |
| CSPCo | | | 203,306 | | | 9,029 | | | 101,965 | | | 5,666 | | | (24,202) | | | 350,000 |
| I&M | | | 491,107 | | | 210,813 | | | 109,469 | | | 110,454 | | | 114,012 | | | 500,000 |
| OPCo | | | 522,934 | | | 451,832 | | | 255,870 | | | 302,420 | | | 438,352 | | | 600,000 |
| PSO | | | 77,976 | | | 284,647 | | | 56,378 | | | 61,328 | | | 62,695 | | | 300,000 |
| SWEPCo | | | 62,871 | | | 158,843 | | | 18,530 | | | 61,828 | | | 34,883 | | | 350,000 |
The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:
| | | Years Ended December 31, |
| | | 2010 | | 2009 | | 2008 |
| Maximum Interest Rate | | 0.55% | | 2.28% | | 5.47% |
| Minimum Interest Rate | | 0.09% | | 0.15% | | 2.28% |
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the years ended December 31, 2010, 2009 and 2008 are summarized for all Registrant Subsidiaries in the following table:
| | | Average Interest Rate | | Average Interest Rate |
| | | for Funds Borrowed | | for Funds Loaned |
| | | from Utility Money Pool for | | to Utility Money Pool for |
| | | Years Ended December 31, | | Years Ended December 31, |
| Company | | 2010 | | 2009 | | 2008 | | 2010 | | 2009 | | 2008 |
| APCo | | 0.26 | % | | 0.89 | % | | 3.66 | % | | - | % | | - | % | | 3.25 | % |
| CSPCo | | 0.18 | % | | 1.05 | % | | 3.59 | % | | 0.26 | % | | 0.57 | % | | 3.29 | % |
| I&M | | 0.43 | % | | 1.46 | % | | 3.35 | % | | 0.24 | % | | 0.26 | % | | - | % |
| OPCo | | - | % | | 1.21 | % | | 3.24 | % | | 0.21 | % | | 0.22 | % | | 3.82 | % |
| PSO | | 0.31 | % | | 2.01 | % | | 3.32 | % | | 0.17 | % | | 0.56 | % | | 4.53 | % |
| SWEPCo | | 0.19 | % | | 1.66 | % | | 3.38 | % | | 0.27 | % | | 0.52 | % | | 3.12 | % |
Interest expense related to the Utility Money Pool is included in Interest Expense on each of the Registrant Subsidiaries’ Financial Statements. The Registrant Subsidiaries incurred interest expense for amounts borrowed from the Utility Money Pool as follows:
| | | Years Ended December 31, |
| Company | | 2010 | | 2009 | | 2008 |
| | | | | | (in thousands) | | | |
| APCo | | $ | 611 | | $ | 1,887 | | $ | 6,076 |
| CSPCo | | | 11 | | | 1,081 | | | 2,287 |
| I&M | | | 17 | | | 924 | | | 7,903 |
| OPCo | | | 5 | | | 2,075 | | | 4,912 |
| PSO | | | 102 | | | 86 | | | 1,856 |
| SWEPCo | | | 11 | | | 68 | | | 1,480 |
Interest income related to the Utility Money Pool is included in Interest Income on each of the Registrant Subsidiaries’ Financial Statements. The Registrant Subsidiaries earned interest income for amounts advanced to the Utility Money Pool as follows:
| | | | Years Ended December 31, |
| | Company | | 2010 | | 2009 | | 2008 |
| | | | | | | (in thousands) | | | |
| | APCo | | $ | 9 | | $ | - | | $ | 872 |
| | CSPCo | | | 208 | | | - | | | 880 |
| | I&M | | | 219 | | | 129 | | | - |
| | OPCo | | | 500 | | | 228 | | | 79 |
| | PSO | | | 19 | | | 322 | | | 293 |
| | SWEPCo | | | 438 | | | 278 | | | 2,540 |
| Short-term Debt | | | | | | | | |
| | | | | | | | | | | | |
| The Registrant Subsidiaries’ outstanding short-term debt was as follows: |
| | | | | December 31, | |
| | | | | 2010 | 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) | $ | 6,217 | 2.15 | % | $ | 6,890 | 2.06 | % |
| | | | | | | | | | | | |
| | (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, of which $750 million may be issued under the credit facility that matures in April 2012 as letters of credit. In June 2010, AEP terminated one of the $1.5 billion facilities, which was scheduled to mature in March 2011, and replaced it with a new $1.5 billion credit facility which matures in June 2013 and allows for the issuance of up to $600 million as letters of credit. As of December 31, 2010, the maximum future payments for letters of credit issued under the two $1.5 billion credit facilities were $150 thousand for I&M and $4 million for SWEPCo.
In June 2010, the Registrant Subsidiaries and certain other companies in the AEP System reduced a $627 million credit agreement that matures in April 2011 to $478 million. Under the facility, letters of credit may be issued. As of December 31, 2010, $477 million of letters of credit were issued to support variable rate Pollution Control Bonds as follows:
| Company | | Amount |
| | | (in thousands) |
| APCo | | $ | 232,292 |
| I&M | | | 77,886 |
| OPCo | | | 166,899 |
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 Subsidiaries’ 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 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 December 31, 2010 and 2009 was as follows:
| | | | December 31, |
| Company | | 2010 | | 2009 |
| | | | (in thousands) |
| APCo | | $ | 145,515 | | $ | 143,938 |
| CSPCo | | | 175,997 | | | 169,095 |
| I&M | | | 123,366 | | | 130,193 |
| OPCo | | | 168,701 | | | 160,977 |
| PSO | | | 121,679 | | | 73,518 |
| SWEPCo | | | 135,092 | | | 117,297 |
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:
| | | | Years Ended December 31, |
| Company | | 2010 | | 2009 | | 2008 |
| | | | (in thousands) |
| APCo | | $ | 9,194 | | $ | 5,132 | | $ | 6,140 |
| CSPCo | | | 11,412 | | | 11,225 | | | 12,744 |
| I&M | | | 6,770 | | | 6,191 | | | 7,213 |
| OPCo | | | 9,218 | | | 8,769 | | | 10,003 |
| PSO | | | 5,406 | | | 6,954 | | | 10,936 |
| SWEPCo | | | 5,688 | | | 6,171 | | | 7,992 |
The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were:
| | | | Years Ended December 31, |
| Company | | 2010 | | 2009 | | 2008 |
| | | | (in thousands) |
| APCo | | $ | 1,418,487 | | $ | 1,258,860 | | $ | 1,029,779 |
| CSPCo | | | 1,750,902 | | | 1,627,444 | | | 1,640,598 |
| I&M | | | 1,283,955 | | | 1,228,502 | | | 1,178,473 |
| OPCo | | | 1,744,707 | | | 1,574,323 | | | 1,630,446 |
| PSO | | | 1,196,586 | | | 1,028,770 | | | 1,484,556 |
| SWEPCo | | | 1,402,525 | | | 1,300,393 | | | 1,347,899 |
15. RELATED PARTY TRANSACTIONS
For other related party transactions, also see “Utility Money Pool – AEP System” and “Sale of Receivables – AEP Credit” sections of Note 14.
AEP Power Pool
APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement, dated July 6, 1951, as amended, defining how they share the costs and benefits associated with their generating plants. This sharing is based upon each company’s MLR, which is calculated monthly on the basis of each company’s maximum peak demand in relation to the sum of the maximum peak demands of all five companies during the preceding 12 months. In December 2010, each AEP Power Pool member gave notice to AEPSC and the other AEP Power Pool members of its decision to terminate the Interconnection Agreement effective January 2014 or such other date approved by the FERC. It is unknown at this time what will replace the Interconnection Agreement. In addition, since 1995, APCo, CSPCo, I&M, KPCo an d OPCo have been parties to the AEP System Interim Allowance Agreement, which provides, among other things, for the transfer of SO2 allowances associated with the transactions under the Interconnection Agreement.
Power, gas and risk management activities are conducted by AEPSC and profits and losses are allocated under the SIA to AEP Power Pool members, PSO and SWEPCo. Risk management activities involve the purchase and sale of electricity and gas under physical forward contracts at fixed and variable prices. In addition, the risk management of electricity, and to a lesser extent gas contracts, includes exchange traded futures and options and OTC options and swaps. The majority of these transactions represent physical forward contracts in the AEP System’s traditional marketing area and are typically settled by entering into offsetting contracts. In addition, AEPSC enters into transactions for the purchase and sale of electricity and gas options, futures and swaps, and for the forward purchase and sale of electricity outside of the AEP System’s traditional marketing area.
CSW Operating Agreement
PSO, SWEPCo and AEPSC are parties to a Restated and Amended Operating Agreement originally dated as of January 1, 1997 (CSW Operating Agreement), which was approved by the FERC. The CSW Operating Agreement requires PSO and SWEPCo to maintain adequate annual planning reserve margins and requires that capacity in excess of the required margins be made available for sale to other operating companies as capacity commitments. Parties are compensated for energy delivered to recipients based upon the deliverer’s incremental cost plus a portion of the recipient’s savings realized by the purchaser that avoids the use of more costly alternatives. Revenues and costs arising from third party sales are generally shared based on the amount of energy PSO or SWEPCo contributes that is sold to third partie s.
System Integration Agreement (SIA)
The SIA provides for the integration and coordination of AEP East companies’ and AEP West companies’ zones. This includes joint dispatch of generation within the AEP System and the distribution, between the two zones, of costs and benefits associated with the transfers of power between the two zones (including sales to third parties and risk management and trading activities). The SIA is designed to function as an umbrella agreement in addition to the Interconnection Agreement and the CSW Operating Agreement, each of which controls the distribution of costs and benefits within a zone.
Power generated, allocated or provided under the Interconnection Agreement or CSW Operating Agreement to any Registrant Subsidiary is primarily sold to customers by such Registrant Subsidiary at rates approved (other than in Ohio) by the public utility commission in the jurisdiction of sale. In Ohio, such rates are based on a statutory formula as that jurisdiction transitions to the use of market rates for generation.
Under both the Interconnection Agreement and CSW Operating Agreement, power generated that is not needed to serve the native load of any Registrant Subsidiary is sold in the wholesale market by AEPSC on behalf of the generating subsidiary.
Affiliated Revenues and Purchases
The following tables show the revenues derived from sales to the pools, direct sales to affiliates, natural gas contracts with AEPES and other revenues for the years ended December 31, 2010, 2009 and 2008:
| Related Party Revenues | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | | (in thousands) |
| Year Ended December 31, 2010 | | | | | | | | | | | | | | | | | | |
| | Sales to AEP Power Pool | | $ | 158,873 | | $ | 64,467 | | $ | 327,992 | | $ | 891,424 | | $ | - | | $ | - |
| | Direct Sales to East Affiliates | | | 123,832 | | | - | | | - | | | 115,406 | | | 1,210 | | | 1,248 |
| | Direct Sales to West Affiliates | | | 3,471 | | | 1,900 | | | 1,931 | | | 2,225 | | | 19,629 | | | 39,851 |
| | Direct Sales to AEPEP | | | - | | | - | | | - | | | - | | | - | | | (286) |
| | Direct Sales to Transmission Companies | | | 44 | | | 113 | | | 1,848 | | | 123 | | | 30 | | | 1 |
| | Natural Gas Contracts with AEPES | | | (2,171) | | | (1,072) | | | (1,087) | | | (1,258) | | | 2 | | | 3 |
| | Other Revenues | | | 32,158 | | | 17,586 | | | 267 | | | 18,003 | | | 2,657 | | | 11,053 |
| | Total Affiliated Revenues | | $ | 316,207 | | $ | 82,994 | | $ | 330,951 | | $ | 1,025,923 | | $ | 23,528 | | $ | 51,870 |
| Related Party Revenues | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | | (in thousands) |
| Year Ended December 31, 2009 | | | | | | | | | | | | | | | | | | |
| | Sales to AEP Power Pool | | $ | 130,331 | | $ | 57,373 | | $ | 198,579 | | $ | 935,563 | | $ | - | | $ | - |
| | Direct Sales to East Affiliates | | | 123,549 | | | - | | | - | | | 84,078 | | | 3,136 | | | 1,220 |
| | Direct Sales to West Affiliates | | | 2,255 | | | 1,169 | | | 1,154 | | | 1,384 | | | 39,197 | | | 16,434 |
| | Direct Sales to AEPEP | | | - | | | - | | | - | | | - | | | - | | | (659) |
| | Natural Gas Contracts with AEPES | | | (8,340) | | | (4,866) | | | (4,637) | | | (6,142) | | | (328) | | | (387) |
| | Other Revenues | | | 15,594 | | | 13,537 | | | 1,055 | | | 19,407 | | | 3,751 | | | 12,710 |
| | Total Affiliated Revenues | | $ | 263,389 | | $ | 67,213 | | $ | 196,151 | | $ | 1,034,290 | | $ | 45,756 | | $ | 29,318 |
| Related Party Revenues | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | | (in thousands) |
| Year Ended December 31, 2008 | | | | | | | | | | | | | | | | | | |
| | Sales to AEP Power Pool | | $ | 219,305 | | $ | 101,743 | | $ | 292,183 | | $ | 849,574 | | $ | - | | $ | - |
| | Direct Sales to East Affiliates | | | 92,225 | | | - | | | - | | | 74,465 | | | 4,246 | | | 3,438 |
| | Direct Sales to West Affiliates | | | 16,558 | | | 9,849 | | | 9,483 | | | 11,505 | | | 90,545 | | | 33,493 |
| | Natural Gas Contracts with AEPES | | | (2,029) | | | (1,203) | | | (1,085) | | | (689) | | | (467) | | | (552) |
| | Other Revenues | | | 2,676 | | | 12,560 | | | 2,160 | | | 5,613 | | | 7,278 | | | 14,463 |
| | Total Affiliated Revenues | | $ | 328,735 | | $ | 122,949 | | $ | 302,741 | | $ | 940,468 | | $ | 101,602 | | $ | 50,842 |
The following tables show the purchased power expense incurred for purchases from the pools and affiliates for the years ended December 31, 2010, 2009 and 2008:
| Related Party Purchases | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | | (in thousands) |
| Year Ended December 31, 2010 | | | | | | | | | | | | | | | | | | |
| | Purchases from AEP Power Pool | | $ | 916,791 | | $ | 294,838 | | $ | 91,129 | | $ | 90,576 | | $ | - | | $ | - |
| | Direct Purchases from East Affiliates | | | - | | | - | | | - | | | - | | | 6,162 | | | 4,078 |
| | Direct Purchases from West Affiliates | | | 825 | | | 458 | | | 466 | | | 538 | | | 39,851 | | | 19,629 |
| | Purchases from AEGCo | | | - | | | 113,801 | | | 235,740 | | | - | | | - | | | - |
| | Gas Purchases from AEPES | | | - | | | - | | | - | | | 2,857 | | | - | | | - |
| | Total Purchases | | $ | 917,616 | | $ | 409,097 | | $ | 327,335 | | $ | 93,971 | | $ | 46,013 | | $ | 23,707 |
| Related Party Purchases | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | | (in thousands) |
| Year Ended December 31, 2009 | | | | | | | | | | | | | | | | | | |
| | Purchases from AEP Power Pool | | $ | 801,624 | | $ | 316,490 | | $ | 99,159 | | $ | 72,360 | | $ | - | | $ | - |
| | Direct Purchases from East Affiliates | | | - | | | - | | | - | | | - | | | 2,896 | | | 3,515 |
| | Direct Purchases from West Affiliates | | | 1,492 | | | 802 | | | 777 | | | 987 | | | 16,435 | | | 39,197 |
| | Direct Purchases from AEGCo | | | - | | | 75,469 | | | 237,372 | | | - | | | - | | | - |
| | Gas Purchases from AEPES | | | - | | | - | | | - | | | 1,251 | | | - | | | - |
| | Total Purchases | | $ | 803,116 | | $ | 392,761 | | $ | 337,308 | | $ | 74,598 | | $ | 19,331 | | $ | 42,712 |
| Related Party Purchases | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | | | | (in thousands) |
| Year Ended December 31, 2008 | | | | | | | | | | | | | | | | | | |
| | Purchases from AEP Power Pool | | $ | 783,048 | | $ | 334,983 | | $ | 135,056 | | $ | 135,514 | | $ | - | | $ | - |
| | Purchases from West System Pool | | | - | | | - | | | - | | | - | | | - | | | 2,867 |
| | Purchases from AEPEP | | | - | | | - | | | - | | | - | | | - | | | 28 |
| | Direct Purchases from East Affiliates | | | - | | | - | | | - | | | - | | | 25,851 | | | 25,333 |
| | Direct Purchases from West Affiliates | | | 2,143 | | | 1,239 | | | 1,195 | | | 1,483 | | | 33,493 | | | 90,545 |
| | Direct Purchases from AEGCo | | | - | | | 77,296 | | | 247,931 | | | - | | | - | | | - |
| | Gas Purchases from AEPES | | | - | | | - | | | - | | | 3,689 | | | - | | | - |
| | Total Purchases | | $ | 785,191 | | $ | 413,518 | | $ | 384,182 | | $ | 140,686 | | $ | 59,344 | | $ | 118,773 |
The above summarized related party revenues and expenses are reported as Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates on the income statements of each Registrant Subsidiary. Since the Registrant Subsidiaries are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses.
System Transmission Integration Agreement
AEP’s System Transmission Integration Agreement provides for the integration and coordination of the planning, operation and maintenance of the transmission facilities of AEP East companies’ and AEP West companies’ zones. Similar to the SIA, the System Transmission Integration Agreement functions as an umbrella agreement in addition to the Transmission Agreement (TA) and the Transmission Coordination Agreement (TCA). The System Transmission Integration Agreement contains two service schedules that govern:
| · | The allocation of transmission costs and revenues and |
| · | The allocation of third-party transmission costs and revenues and AEP System dispatch costs. |
The System Transmission Integration Agreement anticipates that additional service schedules may be added as circumstances warrant.
APCo, CSPCo, I&M, KPCo and OPCo are parties to the TA, dated April 1, 1984, as amended, defining how they share the costs associated with their relative ownership of the extra-high-voltage transmission system (facilities rated 345 kV and above) and certain facilities operated at lower voltages (138 kV and above). Like the Interconnection Agreement, this sharing is based upon each company’s MLR. The FERC approved a new TA effective November 2010. The impacts of the new TA will be phased-in for retail rates, adds KGPCo and WPCo as parties to the agreement and changes the allocation method.
The following table shows the net charges (credits) allocated among the Registrant Subsidiaries, party to the TA, during the years ended December 31, 2010, 2009 and 2008:
| | | | Years Ended December 31, |
| Company | | 2010 | | 2009 | | 2008 |
| | | (in thousands) |
| APCo | | $ | (16,079) | | $ | (12,535) | | $ | (29,146) |
| CSPCo | | | 42,516 | | | 51,309 | | | 55,273 |
| I&M | | | (25,188) | | | (38,400) | | | (37,398) |
| OPCo | | | 6,765 | | | 8,461 | | | 13,294 |
The net charges (credits) shown above are recorded in Other Operation expense on the income statements.
PSO, SWEPCo, TNC and AEPSC are parties to the TCA, originally dated January 1, 1997, as amended. The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with overseeing the coordinated planning of the transmission facilities of the parties to the agreement, including the performance of transmission planning studies, the interaction of such companies with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the Open Access Transmission Tariff (OATT) filed with the FERC and the rules of the FERC relating to such a tariff.
Under the TCA, the parties to the agreement delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The allocations have been governed by the FERC-approved OATT for the SPP (with respect to PSO, TNC and SWEPCo).
The following table shows the net charges (credits) allocated among parties to the TCA pursuant to the SPP OATT protocols as described above during the years ended December 31, 2010, 2009 and 2008:
| | | | Years Ended December 31, |
| Company | | 2010 | | 2009 | | 2008 |
| | | (in thousands) |
| PSO | | $ | 10,600 | | $ | 11,100 | | $ | 8,200 |
| SWEPCo | | | (10,500) | | | (11,100) | | | (8,200) |
The net charges (credits) shown above are recorded in the Other Operation expense on PSO’s and SWEPCo’s income statements.
Assignment from SWEPCo to AEPEP
On March 1, 2008, SWEPCo assigned its portion of a 20-year Purchase Power Agreement (PPA) to AEPEP. In addition to the PPA assignment, an intercompany agreement was executed between AEPEP and SWEPCo to provide SWEPCo with future margins related to its share. SWEPCo also retained the rights to the Renewable Energy Credit Offsets from the PPA. The PPA and intercompany agreements are effective through 2019. SWEPCo recorded losses of $286 thousand and $659 thousand and revenue of $903 thousand from AEPEP in Sales to AEP Affiliates on its 2010, 2009 and 2008 Consolidated Statements of Income, respectively.
ERCOT Contracts Transferred to AEPEP
Effective January 1, 2007, PSO and SWEPCo transferred certain existing ERCOT energy marketing contracts to AEPEP and entered into intercompany financial and physical purchase and sale agreements with AEPEP. This was done to lock in PSO and SWEPCo’s margins on ERCOT trading and marketing contracts and to transfer the future associated commodity price and credit risk to AEPEP. The contracts ended in December 2009.
PSO and SWEPCo have historically presented third party ERCOT trading and marketing activity on a net basis in Revenues - Electric Generation, Transmission and Distribution. The applicable ERCOT third party trading and marketing contracts that were not transferred to AEPEP will remain until maturity on PSO’s and SWEPCo’s balance sheets and will be presented on a net basis in Sales to AEP Affiliates on PSO’s and SWEPCo’s income statements.
The following tables indicate the sales to AEPEP and the amounts reclassified from third party to affiliates:
| |
| | | | Year Ended December 31, 2009 |
| | | | | | Third Party Amounts | | Net Amount |
| | | | Net Settlement | | Reclassified to | | Included in Sales |
| Company | | with AEPEP | | Affiliate | | to AEP Affiliates |
| | | (in thousands) |
| PSO | | $ | (3,871) | | $ | 4,318 | | $ | 447 |
| SWEPCo | | | (4,569) | | | 5,098 | | | 529 |
| |
| | | | Year Ended December 31, 2008 |
| | | | | | Third Party Amounts | | Net Amount |
| | | | Net Settlement | | Reclassified to | | Included in Sales |
| Company | | with AEPEP | | Affiliate | | to AEP Affiliates |
| | | (in thousands) |
| PSO | | $ | 79,445 | | $ | (76,000) | | $ | 3,445 |
| SWEPCo | | | 84,095 | | | (80,032) | | | 4,063 |
CSPCo Transfer of Property
In May 2009, CSPCo transferred a parking garage to AEP through a dividend. AEP then transferred the property to AEPSC through a capital contribution. The transfers were effective May 2009 and were recorded at net book value of $8 million.
Natural Gas Contracts with DETM
In 2003, AEPES assigned to AEPSC, as agent for the AEP East companies, approximately $97 million (negative value) associated with its natural gas contracts with DETM. The assignment was executed in order to consolidate DETM positions within AEP. Beginning in 2007, PSO and SWEPCo were allocated a portion of the DETM assignment based on the SIA methodology of sharing trading and marketing margins between the AEP East companies, PSO and SWEPCo. Concurrently, in order to ensure that there would be no financial impact to the AEP East companies, PSO or SWEPCo as a result of the assignment, AEPES and AEPSC entered into agreements requiring AEPES to reimburse AEPSC for any related cash settlements and all income related to the assigned contracts. The agreement between AEPSC and AEPES ended December 31, 2010, coinciding with the settlement of the remaining DETM contracts. The following table represents the Registrant Subsidiaries’ risk management liabilities related to DETM at December 31, 2009:
| | | | December 31, |
| Company | | 2009 |
| | | (in thousands) |
| APCo | | $ | 2,730 |
| CSPCo | | | 1,383 |
| I&M | | | 1,395 |
| OPCo | | | 1,611 |
Fuel Agreement between OPCo and AEPES
OPCo and National Power Cooperative, Inc (NPC) have an agreement whereby OPCo operates a 500 MW gas plant owned by NPC (Mone Plant). AEPES entered into a fuel management agreement with OPCo and NPC to manage and procure fuel for the Mone Plant. The gas purchased by AEPES and used in generation is first sold to OPCo then allocated to the AEP East companies, who have an agreement to purchase 100% of the available generating capacity from the plant through May 2012. The related purchases of gas managed by AEPES were as follows:
| | | | Years Ended December 31, |
| Company | | 2010 | | 2009 | | 2008 |
| | | (in thousands) |
| APCo | | $ | 940 | | $ | 431 | | $ | 1,204 |
| CSPCo | | | 535 | | | 229 | | | 707 |
| I&M | | | 547 | | | 224 | | | 681 |
| OPCo | | | 640 | | | 279 | | | 840 |
These purchases are reflected in Purchased Electricity for Resale on the income statements.
Unit Power Agreements (UPA)
Lawrenceburg UPA between CSPCo and AEGCo
In March 2007, CSPCo and AEGCo entered into a 10-year UPA for the entire output from the Lawrenceburg Generating Station effective with AEGCo’s purchase of the plant in May 2007. The UPA has an option for an additional 2-year period. I&M operates the plant under an agreement with AEGCo. Under the UPA, CSPCo pays AEGCo for the capacity, depreciation, fuel, operation and maintenance and tax expenses. These payments are due regardless of whether the plant is operating. The fuel and operation and maintenance payments are based on actual costs incurred. All expenses are trued up periodically.
UPA between AEGCo and I&M
A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances.
UPA between AEGCo and KPCo
Pursuant to an assignment between I&M and KPCo and a UPA between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo pays to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo UPA ends in December 2022.
Cook Coal Terminal
Cook Coal Terminal, a division of OPCo, performs coal transloading services at cost for APCo and I&M. OPCo included revenues for these services in Other Revenues – Affiliated and expenses in Other Operation expense on its Consolidated Statements of Income. The coal transloading revenues in 2010, 2009 and 2008 were as follows:
| | | | Years Ended December 31, |
| Company | | 2010 | | 2009 | | 2008 |
| | | (in thousands) |
| APCo | | $ | - | | $ | 916 | | $ | 1,000 |
| I&M | | | 17,208 | | | 18,908 | | | 15,368 |
APCo and I&M recorded the cost of transloading services in Fuel on their balance sheets.
In addition, Cook Coal Terminal provided coal transloading services for OVEC in 2008. Cook Coal Terminal did not provide coal transloading services for OVEC in 2009 or 2010. OPCo recorded revenue as Other Revenues – Nonaffiliated on its Consolidated Statements of Income in the amount of $59 thousand in 2008. OVEC is 43.47% owned by AEP (includes CSPCo’s 4.3% ownership of OVEC).
In 2010, 2009 and 2008, Cook Coal Terminal also performed railcar maintenance services at cost for APCo, I&M, PSO and SWEPCo. OPCo included revenues for these services in Sales to AEP Affiliates and expenses in Other Operation expense on its Consolidated Statements of Income. The railcar maintenance revenues were as follows:
| | | | Years Ended December 31, |
| Company | | 2010 | | 2009 | | 2008 |
| | | (in thousands) |
| APCo | | $ | 7 | | $ | 98 | | $ | 39 |
| I&M | | | 1,870 | | | 2,045 | | | 2,720 |
| PSO | | | 522 | | | 510 | | | 1,160 |
| SWEPCo | | | 1,044 | | | 914 | | | 434 |
APCo, I&M, PSO and SWEPCo recorded the cost of the railcar maintenance services in Fuel on their balance sheets.
In addition, Cook Coal Terminal provides railcar maintenance services for OVEC. OPCo recorded revenue as Other Revenues – Nonaffiliated on its Consolidated Statements of Income in the amount of $1 million, for each year in 2010, 2009 and 2008.
SWEPCo Railcar Facility
SWEPCo operates a railcar maintenance facility in Alliance, Nebraska. The facility performs maintenance on its own railcars as well as railcars belonging to I&M, PSO and third parties. SWEPCo billed I&M $1.8 million and $2.2 million for railcar services provided in 2010 and 2009, respectively, and billed PSO $655 thousand and $425 thousand in 2010 and 2009, respectively. These billings, for SWEPCo, and costs, for I&M and PSO, are recorded in Fuel on the balance sheets.
I&M Barging, Urea Transloading and Other Services
I&M provides barging, urea transloading and other transportation services to affiliates. Urea is a chemical used to control NOx emissions at certain generation plants in the AEP System. I&M recorded revenues from barging, transloading and other services as Other Revenues – Affiliated on its Consolidated Statements of Income. The affiliated companies recorded these costs paid to I&M as fuel expense or other operation expense. The amount of affiliated revenues and affiliated expenses were:
| | | | Years Ended December 31, |
| Company | | 2010 | | 2009 | | 2008 |
| | | (in thousands) |
| I&M – Revenues | | $ | 105,811 | | $ | 94,921 | | $ | 103,436 |
| AEGCo – Expense | | | 12,548 | | | 13,167 | | | 17,038 |
| APCo – Expense | | | 28,241 | | | 29,442 | | | 27,058 |
| KPCo – Expense | | | 133 | | | 112 | | | 9 |
| OPCo – Expense | | | 44,160 | | | 38,039 | | | 40,950 |
| AEP River Operations LLC – Expense (Nonutility | | | | | | | | | |
| | Subsidiary of AEP) | | | 20,729 | | | 14,161 | | | 18,381 |
In addition, I&M provided transloading services to OVEC. I&M recorded revenues of $112 thousand, $135 thousand and $3 thousand for 2010, 2009 and 2008, respectively, in Other Revenues – Nonaffiliated on its Consolidated Statements of Income.
Services Provided by AEP River Operations LLC
AEP River Operations LLC provides services for barge towing, chartering and general and administrative expenses to I&M. The costs are recorded by I&M as Other Operation expense. For the years ended December 31, 2010, 2009 and 2008, I&M recorded expenses of $28 million, $24 million and $37 million, respectively, for these activities.
Central Machine Shop
APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. APCo defers on its balance sheet the cost of performing the services, then transfers the cost to the affiliate for reimbursement. The AEP subsidiaries recorded these billings as capital or maintenance expense depending on the nature of the services received. These billings are recoverable from customers. The following table provides the amounts billed by APCo to the following affiliates:
| | | | Years Ended December 31, |
| Company | | 2010 | | 2009 | | 2008 |
| | | (in thousands) |
| AEGCo | | $ | 180 | | $ | 31 | | $ | 138 |
| CSPCo | | | 397 | | | 1,306 | | | 682 |
| I&M | | | 2,112 | | | 2,818 | | | 2,714 |
| KGPCo | | | - | | | 5 | | | - |
| KPCo | | | 368 | | | 358 | | | 1,183 |
| OPCo | | | 3,268 | | | 2,831 | | | 1,944 |
| PSO | | | 412 | | | 848 | | | 1,225 |
| SWEPCo | | | 560 | | | 966 | | | 288 |
In addition, APCo billed OVEC and IKEC a total of $541 thousand, $202 thousand and $303 thousand for the years ended December 31, 2010, 2009 and 2008, respectively.
Affiliate Coal Purchases
In 2008, OPCo entered into contracts to sell excess coal purchases to certain AEP subsidiaries through 2010. These sales (purchases) are reflected in Sales to AEP Affiliates on the income statements. The following table shows the realized and unrealized amounts recorded for the years ended December 31, 2010, 2009 and 2008:
| | | Years Ended December 31, |
| Company | | 2010 | | 2009 | | 2008 |
| | | (in thousands) |
| APCo | | $ | (2,830) | | $ | (1,573) | | $ | (187) |
| CSPCo | | | (1,558) | | | (783) | | | (90) |
| I&M | | | (1,383) | | | (813) | | | (92) |
| KPCo | | | (837) | | | (340) | | | (36) |
| OPCo | | | 8,930 | | | 5,022 | | | 534 |
| PSO | | | (796) | | | (585) | | | (48) |
| SWEPCo | | | (1,526) | | | (928) | | | (81) |
Affiliate Railcar Agreement
Certain AEP subsidiaries have an agreement providing for the use of each other’s leased or owned railcars when available. The agreement specifies that the company using the railcar will be billed, at cost, by the company furnishing the railcar. The AEP subsidiaries recorded these costs or reimbursements as costs or reduction of costs, respectively, in Fuel on their balance sheets and such costs are recoverable from customers. The following tables show the net effect of the railcar agreement on the balance sheets:
| Year Ended December 31, 2010 |
| Billing Company |
| | | | | | | | | | | | | | | | | | | | |
| Billed Company | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | | Total |
| | | (in thousands) |
| APCo | | $ | - | | $ | - | | $ | 1,195 | | $ | 1 | | $ | (1) | | $ | 1,195 |
| CSPCo | | | - | | | - | | | - | | | - | | | 9 | | | 9 |
| I&M | | | 142 | | | - | | | 1,536 | | | 123 | | | 502 | | | 2,303 |
| KPCo | | | 399 | | | - | | | 245 | | | - | | | - | | | 644 |
| OPCo | | | 919 | | | 418 | | | - | | | 21 | | | 97 | | | 1,455 |
| PSO | | | 177 | | | 921 | | | 191 | | | - | | | 493 | | | 1,782 |
| SWEPCo | | | 328 | | | 2,162 | | | 594 | | | 110 | | | - | | | 3,194 |
| Total | | $ | 1,965 | | $ | 3,501 | | $ | 3,761 | | $ | 255 | | $ | 1,100 | | $ | 10,582 |
| Year Ended December 31, 2009 |
| Billing Company |
| | | | | | | | | | | | | | | | | | | | |
| Billed Company | | APCo | | I&M | | OPCo | | PSO | | SWEPCo | | Total |
| | | (in thousands) |
| APCo | | $ | - | | $ | 143 | | $ | 1,632 | | $ | 15 | | $ | 44 | | $ | 1,834 |
| CSPCo | | | - | | | - | | | - | | | - | | | 11 | | | 11 |
| I&M | | | 162 | | | - | | | 1,185 | | | 195 | | | 895 | | | 2,437 |
| KPCo | | | 669 | | | - | | | 13 | | | - | | | - | | | 682 |
| OPCo | | | 969 | | | 708 | | | - | | | 37 | | | 179 | | | 1,893 |
| PSO | | | 277 | | | 953 | | | 181 | | | - | | | 562 | | | 1,973 |
| SWEPCo | | | 79 | | | 1,896 | | | 1,312 | | | 136 | | | - | | | 3,423 |
| Total | | $ | 2,156 | | $ | 3,700 | | $ | 4,323 | | $ | 383 | | $ | 1,691 | | $ | 12,253 |
Purchased Power from OVEC
The amounts of power purchased by the Registrant Subsidiaries from OVEC for the years ended December 31, 2010, 2009 and 2008 were:
| | | | Years Ended December 31, |
| Company | | 2010 | | 2009 | | 2008 |
| | | (in thousands) |
| APCo | | $ | 105,307 | | $ | 103,369 | | $ | 94,874 |
| CSPCo | | | 29,809 | | | 29,261 | | | 26,853 |
| I&M | | | 52,687 | | | 51,710 | | | 47,465 |
| OPCo | | | 103,967 | | | 102,057 | | | 93,661 |
The amounts shown above are recoverable from customers and are included in Purchased Electricity for Resale on the income statements.
AEP Power Pool Purchases from OVEC
Beginning in 2006, the AEP Power Pool began purchasing power from OVEC as part of wholesale marketing and risk management activity. These purchases are reflected in Electric Generation, Transmission and Distribution revenues on the income statements. The agreement ended in December 2008. The following table shows the amounts recorded for the year ended December 31, 2008:
| | | | Year Ended |
| Company | | December 31, 2008 |
| | | (in thousands) |
| APCo | | $ | 17,795 |
| CSPCo | | | 10,381 |
| I&M | | | 9,999 |
| OPCo | | | 12,359 |
In January 2010, 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 and purchases serving retail sales are reported in Purchased Electricity for Resale expenses on the income statements. The following table shows the amounts recorded for the year ended December 31, 2010:
| | | | Year Ended December 31, 2010 |
| | | | Reported in | | Reported in |
| Company | | Revenues | | Expenses |
| | | (in thousands) |
| APCo | | $ | 6,631 | | $ | 3,635 |
| CSPCo | | | 3,689 | | | 1,963 |
| I&M | | | 3,721 | | | 1,980 |
| OPCo | | | 4,248 | | | 2,268 |
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 $56 million of lignite from DHLC and recorded these costs in Fuel on its Consolidated Balance Sheet at December 31, 2010.
SWEPCo Transactions with Oxbow Lignite Company
Oxbow Lignite Company, LLC (OLC) is jointly-owned by SWEPCo and CLECO, each owning 50%. As joint-owners, SWEPCo and CLECO have equal representation in OLC regarding ownership, liability, profit and distributions. OLC has surface lease and lignite and coal lease agreements which provide equal rights to each owner to mine the reserves and equal liability for the depletion costs. DHLC is the exclusive miner of OLC’s reserves and 100% of the lignite mined is sold to SWEPCo and CLECO. SWEPCo paid OLC $465 thousand for land leases, lignite leases and administrative services in 2010. SWEPCo recorded these costs in Fuel on its Consolidated Balance Sheet at December 31, 2010. See “Oxbow Lignite Company and Red River Mining Company” section of Note 7 for additi onal information regarding the purchase of OLC.
Sales and Purchases of Property – Transmission Companies
In 2009, AEP Transmission Company, LLC (AEP Transco) formed seven wholly-owned transmission companies. AEP Transco is the holding company for the seven new transmission companies. These seven companies consist of: AEP Appalachian Transmission Company, Inc., AEP Indiana Michigan Transmission Company, Inc., AEP Kentucky Transmission Company, Inc., AEP Ohio Transmission Company, Inc., AEP West Virginia Transmission Company, Inc., AEP Oklahoma Transmission Company, Inc. (OKTCo) and AEP Soutwestern Transmission Company, Inc.
PSO began selling transmission property to OKTCo during 2010 for $1.5 million, which was recorded at net book value. There were no gains or losses recorded on the transactions.
Sales and Purchases of Property
Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more for the years ended December 31, 2010, 2009 and 2008 as shown in the following tables:
| | | | Year Ended |
| Companies | | December 31, 2010 |
| | | (in thousands) |
| AEGCo to APCo | | $ | 332 |
| AEGCo to OPCo | | | 190 |
| APCo to I&M | | | 1,090 |
| APCo to KPCo | | | 209 |
| CSPCo to I&M | | | 1,459 |
| CSPCo to KPCo | | | 433 |
| I&M to APCo | | | 444 |
| I&M to OPCo | | | 485 |
| I&M to SWEPCo | | | 218 |
| OPCo to APCo | | | 3,011 |
| OPCo to CSPCo | | | 686 |
| OPCo to I&M | | | 976 |
| OPCo to KPCo | | | 527 |
| SWEPCo to PSO | | | 3,680 |
| TCC to SWEPCo | | | 360 |
| | | | Year Ended |
| Companies | | December 31, 2009 |
| | | (in thousands) |
| APCo to I&M | | $ | 155 |
| I&M to APCo | | | 4,004 |
| I&M to OPCo | | | 6,378 |
| OPCo to APCo | | | 908 |
| OPCo to CSPCo | | | 344 |
| OPCo to I&M | | | 6,026 |
| OPCo to TCC | | | 526 |
| PSO to SWEPCo | | | 118 |
| TCC to APCo | | | 426 |
| TCC to SWEPCo | | | 684 |
| | | | Year Ended |
| Companies | | December 31, 2008 |
| | | (in thousands) |
| APCo to CSPCo | | $ | 858 |
| APCo to I&M | | | 2,720 |
| APCo to OPCo | | | 615 |
| CSPCo to PSO | | | 180 |
| I&M to APCo | | | 653 |
| I&M to KPCo | | | 444 |
| I&M to OPCo | | | 1,992 |
| I&M to PSO | | | 666 |
| OPCo to I&M | | | 1,800 |
| OPCo to PSO | | | 259 |
| PSO to I&M | | | 646 |
| TCC to APCo | | | 220 |
In addition, certain AEP subsidiaries had aggregate affiliated sales and purchases of meters and transformers for the years ended December 31, 2010, 2009 and 2008 as shown in the following tables:
| Year Ended December 31, 2010 |
| | | Purchaser |
| Seller | | APCo | | CSPCo | | I&M | | KGPCo | | KPCo | | OPCo | | PSO | | SWEPCo | | TCC | | TNC | | WPCo | | Total |
| | | (in thousands) |
| APCo | | $ | - | | $ | 17 | | $ | 112 | | $ | 225 | | $ | 139 | | $ | 120 | | $ | 61 | | $ | 31 | | $ | - | | $ | - | | $ | - | | $ | 705 |
| CSPCo | | | 65 | | | - | | | 3 | | | - | | | - | | | 1,164 | | | 74 | | | 908 | | | 157 | | | - | | | 6 | | | 2,377 |
| I&M | | | 138 | | | 46 | | | - | | | - | | | 7 | | | 310 | | | 116 | | | 1 | | | - | | | 63 | | | 14 | | | 695 |
| KGPCo | | | 154 | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | 154 |
| KPCo | | | 364 | | | 9 | | | 6 | | | 23 | | | - | | | 83 | | | - | | | 2 | | | - | | | - | | | - | | | 487 |
| OPCo | | | 146 | | | 6,085 | | | 429 | | | 1 | | | 139 | | | - | | | 5 | | | 196 | | | 8 | | | 10 | | | 366 | | | 7,385 |
| PSO | | | - | | | 42 | | | - | | | - | | | - | | | 2 | | | - | | | 560 | | | 6 | | | 3 | | | - | | | 613 |
| SWEPCo | | | 48 | | | 2 | | | 4 | | | - | | | 3 | | | 212 | | | 1,203 | | | - | | | 70 | | | 11 | | | - | | | 1,553 |
| TCC | | | 22 | | | - | | | 38 | | | - | | | - | | | 23 | | | 6 | | | 266 | | | - | | | 966 | | | - | | | 1,321 |
| TNC | | | 8 | | | - | | | - | | | - | | | - | | | - | | | 1 | | | 70 | | | 642 | | | - | | | 4 | | | 725 |
| WPCo | | | - | | | 1 | | | - | | | - | | | - | | | 110 | | | - | | | - | | | - | | | - | | | - | | | 111 |
| Total | | $ | 945 | | $ | 6,202 | | $ | 592 | | $ | 249 | | $ | 288 | | $ | 2,024 | | $ | 1,466 | | $ | 2,034 | | $ | 883 | | $ | 1,053 | | $ | 390 | | $ | 16,126 |
| Year Ended December 31, 2009 |
| | | Purchaser |
| Seller | | APCo | | CSPCo | | I&M | | KGPCo | | KPCo | | OPCo | | PSO | | SWEPCo | | TCC | | TNC | | WPCo | | Total |
| | | (in thousands) |
| APCo | | $ | - | | $ | 32 | | $ | 87 | | $ | 305 | | $ | 161 | | $ | 115 | | $ | - | | $ | 19 | | $ | 44 | | $ | - | | $ | - | | $ | 763 |
| CSPCo | | | 30 | | | - | | | 26 | | | - | | | - | | | 664 | | | 93 | | | 6 | | | - | | | - | | | 3 | | | 822 |
| I&M | | | 39 | | | 88 | | | - | | | - | | | 50 | | | 315 | | | 119 | | | 65 | | | 37 | | | 75 | | | 17 | | | 805 |
| KGPCo | | | 213 | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | 213 |
| KPCo | | | 505 | | | 23 | | | 64 | | | 7 | | | - | | | 133 | | | 3 | | | 8 | | | - | | | - | | | 1 | | | 744 |
| OPCo | | | 372 | | | 2,748 | | | 297 | | | - | | | 87 | | | - | | | 6 | | | 85 | | | 1 | | | 44 | | | 464 | | | 4,104 |
| PSO | | | 23 | | | 42 | | | 7 | | | - | | | - | | | 1 | | | - | | | 607 | | | 26 | | | 1 | | | - | | | 707 |
| SWEPCo | | | 38 | | | 27 | | | 21 | | | - | | | 26 | | | 58 | | | 1,360 | | | - | | | 162 | | | 28 | | | - | | | 1,720 |
| TCC | | | 13 | | | - | | | 72 | | | - | | | - | | | 19 | | | 2 | | | 87 | | | - | | | 873 | | | - | | | 1,066 |
| TNC | | | 8 | | | - | | | 10 | | | - | | | - | | | 17 | | | 18 | | | 25 | | | 750 | | | - | | | - | | | 828 |
| WPCo | | | - | | | 6 | | | - | | | - | | | - | | | 170 | | | - | | | - | | | - | | | - | | | - | | | 176 |
| Total | | $ | 1,241 | | $ | 2,966 | | $ | 584 | | $ | 312 | | $ | 324 | | $ | 1,492 | | $ | 1,601 | | $ | 902 | | $ | 1,020 | | $ | 1,021 | | $ | 485 | | $ | 11,948 |
| Year Ended December 31, 2008 |
| | | Purchaser |
| Seller | | APCo | | CSPCo | | I&M | | KGPCo | | KPCo | | OPCo | | PSO | | SWEPCo | | TCC | | TNC | | WPCo | | Total |
| | | (in thousands) |
| APCo | | $ | - | | $ | 27 | | $ | 24 | | $ | 386 | | $ | 112 | | $ | 206 | | $ | 9 | | $ | 164 | | $ | 73 | | $ | - | | $ | - | | $ | 1,001 |
| CSPCo | | | 18 | | | - | | | 15 | | | - | | | - | | | 580 | | | 2 | | | - | | | - | | | - | | | 5 | | | 620 |
| I&M | | | 2 | | | 86 | | | - | | | - | | | 15 | | | 270 | | | 25 | | | 2 | | | 5 | | | - | | | 22 | | | 427 |
| KGPCo | | | 253 | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | - | | | 253 |
| KPCo | | | 354 | | | 11 | | | 16 | | | 6 | | | - | | | 121 | | | - | | | 2 | | | 33 | | | - | | | - | | | 543 |
| OPCo | | | 249 | | | 3,446 | | | 613 | | | - | | | 95 | | | - | | | 2 | | | 16 | | | 14 | | | 11 | | | 562 | | | 5,008 |
| PSO | | | 1 | | | 98 | | | - | | | - | | | - | | | 4 | | | - | | | 124 | | | - | | | 25 | | | - | | | 252 |
| SWEPCo | | | - | | | - | | | - | | | - | | | - | | | 3 | | | 655 | | | - | | | 13 | | | 9 | | | - | | | 680 |
| TCC | | | 1 | | | - | | | - | | | - | | | - | | | 1 | | | 9 | | | 535 | | | - | | | 494 | | | - | | | 1,040 |
| TNC | | | - | | | - | | | - | | | - | | | - | | | 9 | | | 28 | | | 26 | | | 334 | | | - | | | - | | | 397 |
| WPCo | | | - | | | 6 | | | 1 | | | - | | | - | | | 152 | | | - | | | - | | | - | | | - | | | - | | | 159 |
| Total | | $ | 878 | | $ | 3,674 | | $ | 669 | | $ | 392 | | $ | 222 | | $ | 1,346 | | $ | 730 | | $ | 869 | | $ | 472 | | $ | 539 | | $ | 589 | | $ | 10,380 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| The amounts above are recorded in Property, Plant and Equipment. Transfers are recorded at cost. |
Global Borrowing Notes
AEP has intercompany notes in place with the Registrant Subsidiaries. The debt is reflected in Long-term Debt – Affiliated on the Registrant Subsidiaries’ balance sheets. The Registrant Subsidiaries accrue interest for their share of the global borrowing and remit the interest to AEP. The accrued interest is reflected in either Accrued Interest or Other Current Liabilities on the Registrant Subsidiaries’ balance sheets. APCo, CSPCo, I&M, OPCo, PSO and SWEPCo participate in the global borrowing arrangement.
Intercompany Billings
The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable bases of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital. Billings between affiliated subsidiaries are capitalized or expensed depending on the nature of the services rendered.
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, DCC Fuel II LLC and DCC Fuel III LLC. 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 each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the years ended December 31, 2010, 2009 and 2008 were $133 million, $99 million and $110 million, respectively. See the tables below for the classification of Sabine’s assets and liabilities on SWEPCo’s Consolidated Balance Sheets.
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 years ended December 31, 2010, 2009 and 2008 were $56 million, $43 million and $44 million, respectively. See the
tables below for the classification of DHLC’s assets and liabilities on SWEPCo’s Consolidated Balance Sheet at December 31, 2009 as well as SWEPCo’s investment and maximum exposure as of December 31, 2010. As of December 31, 2010, DHLC is reported as an equity investment in Deferred Charges and Other Noncurrent Assets on SWEPCo’s 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.
The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.
| SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED |
| VARIABLE INTEREST ENTITIES |
| December 31, 2010 |
| (in millions) |
| | | Sabine | |
| ASSETS | | | | |
| Current Assets | | $ | 50 | |
| Net Property, Plant and Equipment | | | 139 | |
| Other Noncurrent Assets | | | 34 | |
| Total Assets | | $ | 223 | |
| | | | | |
| LIABILITIES AND EQUITY | | | | |
| Current Liabilities | | $ | 33 | |
| Noncurrent Liabilities | | | 190 | |
| Equity | | | - | |
| Total Liabilities and Equity | | $ | 223 | |
| 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:
| | | | | | | |
| | December 31, 2010 | |
| | As Reported on | | | | |
| | the Consolidated | | Maximum | |
| | Balance Sheets | | Exposure | |
| | (in millions) | |
| Capital Contribution from SWEPCo | | $ | 6 | | | $ | 6 | |
| Retained Earnings | | | 2 | | | | 2 | |
| SWEPCo's Guarantee of Debt | | | - | | | | 48 | |
| | | | | | | | | |
| Total Investment in DHLC | | $ | 8 | | | $ | 56 | |
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. In December 2010, I&M entered into a nuclear fuel sale and leaseback transaction with DCC Fuel III LLC. DCC Fuel LLC, DCC Fuel II LLC and DCC Fuel III 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. 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 and October 2010, respectively. Payments on the DCC Fuel III LLC lease are made monthly and began in January 2011. Payments on the leases for the year ended December 31, 2010 were $59 million. No payments were made to DCC Fuel in 2009. The leases were recorded as capital l eases 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 Consolidated Balance Sheets.
The balances below represent the assets and liabilities of the VIE that are consolidated. These balances include intercompany transactions that would be eliminated upon consolidation.
| INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES |
| VARIABLE INTEREST ENTITIES |
| December 31, 2010 and 2009 |
| (in millions) |
| | | DCC Fuel |
| ASSETS | | 2010 | | 2009 |
| Current Assets | | $ | 92 | | $ | 47 |
| Net Property, Plant and Equipment | | | 173 | | | 89 |
| Other Noncurrent Assets | | | 112 | | | 57 |
| Total Assets | | $ | 377 | | $ | 193 |
| | | | | | | |
| LIABILITIES AND EQUITY | | | | | | |
| Current Liabilities | | $ | 79 | | $ | 39 |
| Noncurrent Liabilities | | | 298 | | | 154 |
| Equity | | | - | | | - |
| Total Liabilities and Equity | | $ | 377 | | $ | 193 |
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 has 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 lings are subject to regulation by the FERC. AEP’s subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. All Registrant Subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, no Registrant Subsidiary has 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:
| | | Years Ended December 31, |
| Company | | 2010 | | 2009 | | 2008 |
| | | (in thousands) |
| APCo | | $ | 238,367 | | $ | 200,828 | | $ | 249,897 |
| CSPCo | | | 136,160 | | | 124,055 | | | 135,586 |
| I&M | | | 139,920 | | | 128,372 | | | 147,851 |
| OPCo | | | 196,271 | | | 175,193 | | | 207,773 |
| PSO | | | 102,116 | | | 86,375 | | | 116,576 |
| SWEPCo | | | 147,928 | | | 129,887 | | | 138,753 |
The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows:
| | | | | | | | | | | | | |
| | | December 31, |
| | | 2010 | | 2009 |
| | | As Reported on the | | Maximum | | As Reported on the | | Maximum |
| Company | | Balance Sheet | | Exposure | | Balance Sheet | | Exposure |
| | | (in thousands) |
| APCo | | $ | 23,230 | | $ | 23,230 | | $ | 22,693 | | $ | 22,693 |
| CSPCo | | | 12,676 | | | 12,676 | | | 13,348 | | | 13,348 |
| I&M | | | 12,980 | | | 12,980 | | | 13,119 | | | 13,119 |
| OPCo | | | 16,927 | | | 16,927 | | | 17,647 | | | 17,647 |
| PSO | | | 9,384 | | | 9,384 | | | 8,521 | | | 8,521 |
| SWEPCo | | | 14,465 | | | 14,465 | | | 13,752 | | | 13,752 |
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 ncing would be provided by AEP. For additional information regarding AEGCo’s lease, see “Rockport Lease” section of Note 13.
Total billings from AEGCo were as follows:
| | | | | | | | | | | |
| | | Years Ended December 31, | |
| Company | | 2010 | | 2009 | | 2008 | |
| | | (in thousands) | | | | |
| CSPCo | | | $ | 113,801 | | | $ | 75,469 | | | $ | 113,875 | |
| I&M | | | | 235,741 | | | | 237,372 | | | | 247,932 | |
The carrying amount and classification of variable interest in AEGCo’s accounts payable are as follows:
| | | December 31, |
| | | 2010 | | 2009 |
| | | As Reported on | | | | | As Reported on | | | |
| | | the Consolidated | | Maximum | | the Consolidated | | Maximum |
| Company | | Balance Sheet | | Exposure | | Balance Sheet | | Exposure |
| | | (in thousands) |
| CSPCo | | $ | 18,165 | | $ | 18,165 | | $ | 5,690 | | $ | 5,690 |
| I&M | | | 27,899 | | | 27,899 | | | 22,506 | | | 22,506 |
16. PROPERTY, PLANT AND EQUIPMENT
Depreciation, Depletion and Amortization
The Registrant Subsidiaries provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following table provides the annual composite depreciation rates by functional class generally used by the Registrant Subsidiaries:
| APCo | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| 2010 | | Regulated | | Nonregulated |
| | | | | | | Annual | | | | | | | | Annual | | |
| Functional | | Property, | | | | Composite | | | | Property, | | | | Composite | | |
| Class of | | Plant and | | Accumulated | | Depreciation | | Depreciable | | Plant and | | Accumulated | | Depreciation | | Depreciable |
| Property | | Equipment | | Depreciation | | Rate | | Life Ranges | | Equipment | | Depreciation | | Rate | | Life Ranges |
| | | (in thousands) | | | | (in years) | | (in thousands) | | | | (in years) |
| Generation | | $ | 4,736,150 | | $ | 1,701,839 | | 2.4% | | 40-121 | | $ | - | | $ | - | | - | | - |
| Transmission | | | 1,852,415 | | | 445,671 | | 1.6% | | 25-87 | | | - | | | - | | - | | - |
| Distribution | | | 2,740,752 | | | 562,139 | | 3.2% | | 11-52 | | | - | | | - | | - | | - |
| CWIP | | | 562,280 | | | (18,470) | | N.M. | | N.M. | | | - | | | - | | - | | - |
| Other | | | 314,301 | | | 139,167 | | 7.8% | | 24-55 | | | 33,712 | | | 12,741 | | N.M. | | N.M. |
| Total | | $ | 10,205,898 | | $ | 2,830,346 | | | | | | $ | 33,712 | | $ | 12,741 | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| 2009 | | Regulated | | Nonregulated |
| | | | | | | Annual | | | | | | | | Annual | | |
| Functional | | Property, | | | | Composite | | | | Property, | | | | Composite | | |
| Class of | | Plant and | | Accumulated | | Depreciation | | Depreciable | | Plant and | | Accumulated | | Depreciation | | Depreciable |
| Property | | Equipment | | Depreciation | | Rate | | Life Ranges | | Equipment | | Depreciation | | Rate | | Life Ranges |
| | | (in thousands) | | | | (in years) | | (in thousands) | | | | (in years) |
| Generation | | $ | 4,284,361 | | $ | 1,648,292 | | 2.3% | | 40-121 | | $ | - | | $ | - | | - | | - |
| Transmission | | | 1,813,777 | | | 436,320 | | 1.6% | | 25-87 | | | - | | | - | | - | | - |
| Distribution | | | 2,642,479 | | | 557,963 | | 3.2% | | 11-52 | | | - | | | - | | - | | - |
| CWIP | | | 730,099 | | | (27,062) | | N.M. | | N.M. | | | - | | | - | | - | | - |
| Other | | | 296,149 | | | 123,419 | | 8.9% | | 24-55 | | | 33,348 | | | 12,511 | | N.M. | | N.M. |
| Total | | $ | 9,766,865 | | $ | 2,738,932 | | | | | | $ | 33,348 | | $ | 12,511 | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| |
| 2008 | | Regulated | | Nonregulated |
| | | Annual Composite | | | | Annual Composite | | |
| | | Depreciation | | Depreciable | | Depreciation | | Depreciable |
| Functional Class of Property | | Rate | | Life Ranges | | Rate | | Life Ranges |
| | | | | (in years) | | | | (in years) |
| Generation | | 2.3% | | 40-121 | | - | | - |
| Transmission | | 1.6% | | 25-87 | | - | | - |
| Distribution | | 3.2% | | 11-52 | | - | | - |
| CWIP | | N.M. | | N.M. | | - | | - |
| Other | | 7.5% | | 24-55 | | N.M. | | N.M. |
| | | | | | | | | |
| N.M. Not Meaningful |
| CSPCo | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| 2010 | | Regulated | | Nonregulated |
| | | | | | | Annual | | | | | | | | Annual | | |
| Functional | | Property, | | | | Composite | | | | Property, | | | | Composite | | |
| Class of | | Plant and | | Accumulated | | Depreciation | | Depreciable | | Plant and | | Accumulated | | Depreciation | | Depreciable |
| Property | | Equipment | | Depreciation | | Rate | | Life Ranges | | Equipment | | Depreciation | | Rate | | Life Ranges |
| | | (in thousands) | | | | (in years) | | (in thousands) | | | | (in years) |
| Generation | | $ | - | | $ | - | | - | | - | | $ | 2,686,294 | | $ | 967,882 | | 2.2% | | 50 - 60 |
| Transmission | | | 662,312 | | | 241,393 | | 2.3% | | 33-50 | | | - | | | - | | - | | - |
| Distribution | | | 1,796,023 | | | 617,407 | | 3.5% | | 12-56 | | | - | | | - | | - | | - |
| CWIP | | | 94,845 | | | (2,156) | | N.M. | | N.M. | | | 77,948 | | | 527 | | N.M. | | N.M. |
| Other | | | 179,276 | | | 98,801 | | 8.4% | | N.M. | | | 24,317 | | | 3,258 | | N.M. | | N.M. |
| Total | | $ | 2,732,456 | | $ | 955,445 | | | | | | $ | 2,788,559 | | $ | 971,667 | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| 2009 | | Regulated | | Nonregulated |
| | | | | | | Annual | | | | | | | | Annual | | |
| Functional | | Property, | | | | Composite | | | | Property, | | | | Composite | | |
| Class of | | Plant and | | Accumulated | | Depreciation | | Depreciable | | Plant and | | Accumulated | | Depreciation | | Depreciable |
| Property | | Equipment | | Depreciation | | Rate | | Life Ranges | | Equipment | | Depreciation | | Rate | | Life Ranges |
| | | (in thousands) | | | | (in years) | | (in thousands) | | | | (in years) |
| Generation | | $ | - | | $ | - | | - | | - | | $ | 2,641,860 | | $ | 924,842 | | 2.0% | | 50-60 |
| Transmission | | | 623,680 | | | 231,428 | | 2.2% | | 33-50 | | | - | | | - | | - | | - |
| Distribution | | | 1,745,559 | | | 593,541 | | 3.4% | | 12-56 | | | - | | | - | | - | | - |
| CWIP | | | 112,426 | | | (4,006) | | N.M. | | N.M. | | | 42,655 | | | 10 | | N.M. | | N.M. |
| Other | | | 164,998 | | | 89,968 | | 10.2% | | N.M. | | | 24,317 | | | 3,057 | | N.M. | | N.M. |
| Total | | $ | 2,646,663 | | $ | 910,931 | | | | | | $ | 2,708,832 | | $ | 927,909 | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| 2008 | | Regulated | | Nonregulated |
| | | Annual Composite | | | | Annual Composite | | |
| | | Depreciation | | Depreciable | | Depreciation | | Depreciable |
| Functional Class of Property | | Rate | | Life Ranges | | Rate | | Life Ranges |
| | | | | (in years) | | | | (in years) |
| Generation | | - | | - | | 2.7% | | 40-59 |
| Transmission | | 2.3% | | 33-50 | | - | | - |
| Distribution | | 3.5% | | 12-56 | | - | | - |
| CWIP | | N.M. | | N.M. | | N.M. | | N.M. |
| Other | | 8.7% | | N.M. | | N.M. | | N.M. |
| | | | | | | | | |
| N.M. Not Meaningful |
| OPCo | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| 2010 | | Regulated | | Nonregulated |
| | | | | | | Annual | | | | | | | | Annual | | |
| Functional | | Property, | | | | Composite | | | | Property, | | | | Composite | | |
| Class of | | Plant and | | Accumulated | | Depreciation | | Depreciable | | Plant and | | Accumulated | | Depreciation | | Depreciable |
| Property | | Equipment | | Depreciation | | Rate | | Life Ranges | | Equipment | | Depreciation | | Rate | | Life Ranges |
| | | (in thousands) | | | | (in years) | | (in thousands) | | | | (in years) |
| Generation | | $ | - | | $ | - | | - | | - | | $ | 6,890,110 | | $ | 2,526,808 | | 3.7% | | 35-70 |
| Transmission | | | 1,234,677 | | | 491,798 | | 2.3% | | 27-70 | | | - | | | - | | - | | - |
| Distribution | | | 1,626,390 | | | 449,390 | | 3.9% | | 12-55 | | | - | | | - | | - | | - |
| CWIP | | | 98,532 | | | 616 | | N.M. | | N.M. | | | 54,578 | | | 8,624 | | N.M. | | N.M. |
| Other | | | 241,238 | | | 118,485 | | 9.9% | | N.M. | | | 118,016 | | | 11,056 | | N.M. | | N.M. |
| Total | | $ | 3,200,837 | | $ | 1,060,289 | | | | | | $ | 7,062,704 | | $ | 2,546,488 | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| 2009 | | Regulated | | Nonregulated |
| | | | | | | Annual | | | | | | | | Annual | | |
| Functional | | Property, | | | | Composite | | | | Property, | | | | Composite | | |
| Class of | | Plant and | | Accumulated | | Depreciation | | Depreciable | | Plant and | | Accumulated | | Depreciation | | Depreciable |
| Property | | Equipment | | Depreciation | | Rate | | Life Ranges | | Equipment | | Depreciation | | Rate | | Life Ranges |
| | | (in thousands) | | | | (in years) | | (in thousands) | | | | (in years) |
| Generation | | $ | - | | $ | - | | - | | - | | $ | 6,731,469 | | $ | 2,283,322 | | 3.3% | | 35-70 |
| Transmission | | | 1,166,557 | | | 473,342 | | 2.3% | | 27-70 | | | - | | | - | | - | | - |
| Distribution | | | 1,567,871 | | | 422,521 | | 3.9% | | 12-55 | | | - | | | - | | - | | - |
| CWIP | | | 95,726 | | | (2,623) | | N.M. | | N.M. | | | 103,117 | | | 6,467 | | N.M. | | N.M. |
| Other | | | 231,416 | | | 124,217 | | 11.5% | | N.M. | | | 117,302 | | | 11,650 | | N.M. | | N.M. |
| Total | | $ | 3,061,570 | | $ | 1,017,457 | | | | | | $ | 6,951,888 | | $ | 2,301,439 | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| 2008 | | Regulated | | Nonregulated |
| | | Annual Composite | | | | Annual Composite | | |
| | | Depreciation | | Depreciable | | Depreciation | | Depreciable |
| Functional Class of Property | | Rate | | Life Ranges | | Rate | | Life Ranges |
| | | | | (in years) | | | | (in years) |
| Generation | | - | | - | | 2.7% | | 35-61 |
| Transmission | | 2.3% | | 27-70 | | - | | - |
| Distribution | | 3.9% | | 12-55 | | - | | - |
| CWIP | | N.M. | | N.M. | | N.M. | | N.M. |
| Other | | 8.5% | | N.M. | | N.M. | | N.M. |
| | | | | | | | | |
| N.M. Not Meaningful |
| SWEPCo | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| 2010 | | Regulated | | Nonregulated |
| | | | | | | Annual | | | | | | | | Annual | | |
| Functional | | Property, | | | | Composite | | | | Property, | | | | Composite | | |
| Class of | | Plant and | | Accumulated | | Depreciation | | Depreciable | | Plant and | | Accumulated | | Depreciation | | Depreciable |
| Property | | Equipment | | Depreciation | | Rate | | Life Ranges | | Equipment | | Depreciation | | Rate | | Life Ranges |
| | | (in thousands) | | | | (in years) | | (in thousands) | | | | (in years) |
| Generation | | $ | 2,297,463 | | $ | 1,026,467 | | 1.9% | | 35-68 | | $ | - | | $ | - | | - | | - |
| Transmission | | | 943,724 | | | 272,619 | | 2.4% | | 50-70 | | | - | | | - | | - | | - |
| Distribution | | | 1,611,129 | | | 513,472 | | 2.7% | | 25-65 | | | - | | | - | | - | | - |
| CWIP | | | 1,065,949 | (a) | | 700 | | N.M. | | N.M. | | | 5,654 | | | - | | N.M. | | N.M. |
| Other | | | 403,881 | | | 248,544 | | 7.7% | | 7-47 | | | 228,277 | | | 68,549 | | N.M. | | N.M. |
| Total | | $ | 6,322,146 | | $ | 2,061,802 | | | | | | $ | 233,931 | | $ | 68,549 | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| 2009 | | Regulated | | Nonregulated |
| | | | | | | Annual | | | | | | | | Annual | | |
| Functional | | Property, | | | | Composite | | | | Property, | | | | Composite | | |
| Class of | | Plant and | | Accumulated | | Depreciation | | Depreciable | | Plant and | | Accumulated | | Depreciation | | Depreciable |
| Property | | Equipment | | Depreciation | | Rate | | Life Ranges | | Equipment | | Depreciation | | Rate | | Life Ranges |
| | | (in thousands) | | | | (in years) | | (in thousands) | | | | (in years) |
| Generation | | $ | 1,837,318 | | $ | 1,089,516 | | 2.7% | | 22-68 | | $ | - | | $ | - | | - | | - |
| Transmission | | | 870,069 | | | 266,524 | | 2.6% | | 40-72 | | | - | | | - | | - | | - |
| Distribution | | | 1,447,559 | | | 397,445 | | 3.6% | | 18-67 | | | - | | | - | | - | | - |
| CWIP | | | 1,170,823 | (a) | | (5,920) | | N.M. | | N.M. | | | 5,816 | | | - | | N.M. | | N.M. |
| Other | | | 396,080 | | | 192,006 | | 7.6% | | 7-48 | | | 337,230 | | | 146,762 | | N.M. | | N.M. |
| Total | | $ | 5,721,849 | | $ | 1,939,571 | | | | | | $ | 343,046 | | $ | 146,762 | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| 2008 | | Regulated | | Nonregulated |
| | | Annual Composite | | | | Annual Composite | | |
| | | Depreciation | | Depreciable | | Depreciation | | Depreciable |
| Functional Class of Property | | Rate | | Life Ranges | | Rate | | Life Ranges |
| | | | | (in years) | | | | (in years) |
| Generation | | 2.9% | | 19-68 | | 2.9% | | 30-37 |
| Transmission | | 2.7% | | 44-65 | | - | | - |
| Distribution | | 3.5% | | 19-56 | | - | | - |
| CWIP | | N.M. | | N.M. | | N.M. | | N.M. |
| Other | | 7.1% | | 7-45 | | N.M. | | N.M. |
| | | | | | | | | |
| (a) Includes CWIP related to SWEPCo's Arkansas jurisdictional share of the Turk Plant. |
| | | | | | | | | |
| N.M. Not Meaningful |
| | | I&M | | PSO |
| 2010 | | Regulated | | Regulated |
| | | | | | | Annual | | | | | | | | Annual | | |
| Functional | | Property, | | | | Composite | | | | Property, | | | | Composite | | |
| Class of | | Plant and | | Accumulated | | Depreciation | | Depreciable | | Plant and | | Accumulated | | Depreciation | | Depreciable |
| Property | | Equipment | | Depreciation | | Rate | | Life Ranges | | Equipment | | Depreciation | | Rate | | Life Ranges |
| | | (in thousands) | | | | (in years) | | (in thousands) | | | | (in years) |
| Generation | | $ | 3,774,262 | | $ | 2,085,746 | | 1.6% | | 59-132 | | $ | 1,330,368 | | $ | 648,205 | | 1.8% | | 9-70 |
| Transmission | | | 1,188,665 | | | 408,832 | | 1.4% | | 46-75 | | | 663,994 | | | 161,835 | | 1.9% | | 40-75 |
| Distribution | | | 1,411,095 | | | 361,259 | | 2.5% | | 14-70 | | | 1,686,470 | | | 311,005 | | 2.4% | | 27-65 |
| CWIP | | | 301,534 | | | 33,046 | | N.M. | | N.M. | | | 59,091 | | | (1,958) | | N.M. | | N.M. |
| Other | | | 572,328 | | | 129,703 | | 11.7% | | N.M. | | | 230,286 | | | 135,977 | | 8.3% | | 5-35 |
| Total | | $ | 7,247,884 | | $ | 3,018,586 | | | | | | $ | 3,970,209 | | $ | 1,255,064 | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | I&M | | PSO |
| | | Nonregulated | | Nonregulated |
| | | | | | | Annual | | | | | | | | Annual | | |
| Functional | | Property, | | | | Composite | | | | Property, | | | | Composite | | |
| Class of | | Plant and | | Accumulated | | Depreciation | | Depreciable | | Plant and | | Accumulated | | Depreciation | | Depreciable |
| Property | | Equipment | | Depreciation | | Rate | | Life Ranges | | Equipment | | Depreciation | | Rate | | Life Ranges |
| | | (in thousands) | | | | (in years) | | (in thousands) | | | | (in years) |
| Other | | $ | 147,380 | | $ | 106,412 | | N.M. | | N.M. | | $ | 5,120 | | $ | - | | N.M. | | N.M. |
| | | | | | | | | | | | | | | | | | | | | |
| | | I&M | | PSO |
| 2009 | | Regulated | | Regulated |
| | | | | | | Annual | | | | | | | | Annual | | |
| Functional | | Property, | | | | Composite | | | | Property, | | | | Composite | | |
| Class of | | Plant and | | Accumulated | | Depreciation | | Depreciable | | Plant and | | Accumulated | | Depreciation | | Depreciable |
| Property | | Equipment | | Depreciation | | Rate | | Life Ranges | | Equipment | | Depreciation | | Rate | | Life Ranges |
| | | (in thousands) | | | | (in years) | | (in thousands) | | | | (in years) |
| Generation | | $ | 3,634,215 | | $ | 2,056,271 | | 1.6% | | 59-132 | | $ | 1,300,069 | | $ | 637,317 | | 1.8% | | 9-70 |
| Transmission | | | 1,154,026 | | | 403,760 | | 1.4% | | 46-75 | | | 617,291 | | | 157,999 | | 2.0% | | 40-75 |
| Distribution | | | 1,360,553 | | | 358,231 | | 2.4% | | 14-70 | | | 1,596,355 | | | 311,352 | | 2.4% | | 27-65 |
| CWIP | | | 278,278 | | | 29,931 | | N.M. | | N.M. | | | 67,138 | | | (1,422) | | N.M. | | N.M. |
| Other | | | 605,288 | | | 118,433 | | 12.8% | | N.M. | | | 223,585 | | | 114,931 | | 8.3% | | 5-35 |
| Total | | $ | 7,032,360 | | $ | 2,966,626 | | | | | | $ | 3,804,438 | | $ | 1,220,177 | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | I&M | | PSO |
| | | Nonregulated | | Nonregulated |
| | | | | | | Annual | | | | | | | | Annual | | |
| Functional | | Property, | | | | Composite | | | | Property, | | | | Composite | | |
| Class of | | Plant and | | Accumulated | | Depreciation | | Depreciable | | Plant and | | Accumulated | | Depreciation | | Depreciable |
| Property | | Equipment | | Depreciation | | Rate | | Life Ranges | | Equipment | | Depreciation | | Rate | | Life Ranges |
| | | (in thousands) | | | | (in years) | | (in thousands) | | | | (in years) |
| Other | | $ | 149,844 | | $ | 107,069 | | N.M. | | N.M. | | $ | 5,120 | | $ | - | | N.M. | | N.M. |
| | | | | | | | | | | | | | | | | | | | | |
| | | I&M | | PSO |
| 2008 | | Regulated | | Regulated |
| | | | | | | | | |
| | | Annual Composite | | Depreciable | | Annual Composite | | Depreciable |
| Functional Class of Property | | Depreciation Rate | | Life Ranges | | Depreciation Rate | | Life Ranges |
| | | | | (in years) | | | | (in years) |
| Generation | | 1.6% | | 59-132 | | 1.7% | | 9-70 |
| Transmission | | 1.4% | | 46-75 | | 1.9% | | 40-75 |
| Distribution | | 2.4% | | 14-70 | | 2.9% | | 27-65 |
| CWIP | | N.M. | | N.M. | | N.M. | | N.M. |
| Other | | 11.3% | | N.M. | | 6.8% | | 5-35 |
| | | | | | | | | |
| | | I&M | | PSO |
| | | Nonregulated | | Nonregulated |
| | | | | | | | | |
| | | Annual Composite | | Depreciable | | Annual Composite | | Depreciable |
| Functional Class of Property | | Depreciation Rate | | Life Ranges | | Depreciation Rate | | Life Ranges |
| | | | | (in years) | | | | (in years) |
| Other | | N.M. | | N.M. | | N.M. | | N.M. |
| | | | | | | | | |
| N.M. Not Meaningful |
The Registrant Subsidiaries provide for depreciation, depletion and amortization of coal-mining assets over each asset's estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. The Registrant Subsidiaries use either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. The Registrant Subsidiaries include these costs in the cost of coal charged to fuel expense.
For cost-based rate-regulated operations, the composite depreciation rate generally includes a component for nonasset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred.
As of January 1, 2010, DHLC was deconsolidated and is now reported as an equity investment on SWEPCo’s 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.
Asset Retirement Obligations (ARO)
The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets, as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable f or such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected.
As of December 31, 2010 and 2009, I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $930 million and $878 million, respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s Consolidated Balance Sheets. As of December 31, 2010 and 2009, the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.2 billion and $1.1 billion, respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s Consolidated Balance Sheets.
The following is a reconciliation of the 2010 and 2009 aggregate carrying amounts of ARO by Registrant Subsidiary:
| | | | ARO at | | | | | | | | Revisions in | | ARO at |
| | | | December 31, | | Accretion | | Liabilities | | Liabilities | | Cash Flow | | December 31, |
| Company | | 2009 | | Expense | | Incurred | | Settled | | Estimates | | 2010 |
| | | (in thousands) |
| APCo (a)(d) | | $ | 125,289 | | $ | 8,541 | | $ | 5,341 | | $ | (4,064) | | $ | 6,817 | | $ | 141,924 |
| CSPCo (a)(d) | | | 40,522 | | | 2,869 | | | 1,452 | | | (1,711) | | | 11,643 | | | 54,775 |
| I&M (a)(b)(d) | | | 894,746 | | | 47,844 | | | 7,216 | | | (1,694) | | | 14,917 | | | 963,029 |
| OPCo (a)(d) | | | 94,221 | | | 8,565 | | | 3,579 | | | (2,497) | | | 30,628 | | | 134,496 |
| PSO (a)(d) | | | 15,652 | | | 1,332 | | | 4,746 | | | (173) | | | - | | | 21,557 |
| SWEPCo (a)(c)(d)(e) | | | 51,684 | (f) | | 4,290 | | | 9,056 | | | (7,709) | | | 2,061 | | | 59,382 |
| | | | | | | | | | | | | | | | | | | | |
| | | | ARO at | | | | | | | | Revisions in | | ARO at |
| | | | December 31, | | Accretion | | Liabilities | | Liabilities | | Cash Flow | | December 31, |
| Company | | 2008 | | Expense | | Incurred | | Settled | | Estimates | | 2009 |
| | | (in thousands) |
| APCo (a)(d) | | $ | 51,879 | | $ | 4,969 | | $ | 38,654 | | $ | (2,656) | | $ | 32,443 | | $ | 125,289 |
| CSPCo (a)(d) | | | 17,428 | | | 1,458 | | | - | | | (2,858) | | | 24,494 | | | 40,522 |
| I&M (a)(b)(d) | | | 902,920 | | | 48,662 | | | 2,396 | | | (1,480) | | | (57,752) | | | 894,746 |
| OPCo (a)(d) | | | 89,316 | | | 7,935 | | | - | | | (3,946) | | | 916 | | | 94,221 |
| PSO (a)(d) | | | 14,826 | | | 1,250 | | | - | | | (390) | | | (34) | | | 15,652 |
| SWEPCo (a)(c)(d)(e) | | | 55,086 | | | 7,384 | | | 6,039 | | | (11,081) | | | 6,673 | | | 64,101 |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
| (a) | Includes ARO related to ash disposal facilities. |
| (b) | Includes ARO related to nuclear decommissioning costs for the Cook Plant ($930 million and $878 million at |
| | December 31, 2010 and 2009, respectively). |
| (c) | Includes ARO related to Sabine and DHLC. |
| (d) | Includes ARO related to asbestos removal. |
| (e) | The current portion of SWEPCo’s ARO, totaling $2.6 million and $3.5 million, at December 31, 2010 and |
| | and 2009 respectively, is included in Other Current Liabilities on SWEPCo’s Consolidated Balance Sheets. |
| (f) | SWEPCo adopted ASU 2009-17 effective January 1, 2010 and deconsolidated DHLC. As a result, SWEPCo |
| | recorded only 50% ($12 million) of the final reclamation based on its share of the obligation instead of the |
| | previous 100%. |
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
The amounts of AFUDC included in Allowance for Equity Funds Used During Construction on the Registrant Subsidiaries’ income statements for 2010, 2009 and 2008 were as follows:
| | | Years Ended December 31, |
| Company | | 2010 | | 2009 | | 2008 |
| | | (in thousands) |
| APCo | | $ | 2,967 | | $ | 7,000 | | $ | 8,938 |
| CSPCo | | | 2,072 | | | 3,382 | | | 3,364 |
| I&M | | | 15,678 | | | 12,013 | | | 965 |
| OPCo | | | 3,877 | | | 2,712 | | | 3,073 |
| PSO | | | 804 | | | 1,787 | | | 1,822 |
| SWEPCo | | | 45,646 | | | 46,737 | | | 14,908 |
The amounts of allowance for borrowed funds used during construction or interest capitalized included in Interest Expense on the Registrant Subsidiaries’ income statements for 2010, 2009 and 2008 were as follows:
| | | Years Ended December 31, |
| Company | | 2010 | | 2009 | | 2008 |
| | | (in thousands) |
| APCo | | $ | 2,251 | | $ | 6,014 | | $ | 9,040 |
| CSPCo | | | 2,311 | | | 5,968 | | | 2,677 |
| I&M | | | 8,500 | | | 8,348 | | | 4,609 |
| OPCo | | | 1,475 | | | 10,538 | | | 25,269 |
| PSO | | | 572 | | | 1,142 | | | 2,174 |
| SWEPCo | | | 33,668 | | | 29,546 | | | 19,800 |
Jointly-owned Electric Facilities
APCo, CSPCo, I&M, OPCo, PSO and SWEPCo have electric facilities that are jointly-owned with affiliated and nonaffiliated companies. Using its own financing, each participating company is obligated to pay its share of the costs of any such jointly-owned facilities in the same proportion as its ownership interest. Each Registrant Subsidiary’s proportionate share of the operating costs associated with such facilities is included in its statements of operations and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows:
| | | | | | | | | Company’s Share at December 31, 2010 |
| | | | | | | | | | | Construction | | |
| | | Fuel | Percent of | Utility Plant | Work in | Accumulated |
| Company | Type | Ownership | in Service | Progress | Depreciation |
| | | | | | | | | (in thousands) |
| APCo | | | | | | | | | | | | | | |
| John E. Amos Generating Station (Unit No. 3) (a) | | Coal | | 33.33 | % | | $ | 472,244 | | $ | 5,638 | | $ | 77,786 |
| | | | | | | | | | | | | | | | |
| CSPCo | | | | | | | | | | | | | | |
| W.C. Beckjord Generating Station | | Coal | | 12.5 | % | | $ | 19,079 | | $ | 248 | | $ | 8,003 |
| | (Unit No. 6) (b) | | | | | | | | | | | | | | |
| Conesville Generating Station (Unit No. 4) (c) | | Coal | | 43.5 | % | | | 300,618 | | | 8,259 | | | 49,121 |
| J.M. Stuart Generating Station (d) | | Coal | | 26.0 | % | | | 506,756 | | | 22,435 | | | 162,869 |
| Wm. H. Zimmer Generating Station (b) | | Coal | | 25.4 | % | | | 771,236 | | | 9,636 | | | 365,989 |
| Transmission | | N/A | | (f) | | | | 62,952 | | | 3,008 | | | 47,957 |
| Total | | | | | | | $ | 1,660,641 | | $ | 43,586 | | $ | 633,939 |
| | | | | | | | | | | | | | | | |
| I&M | | | | | | | | | | | | | | |
| Rockport Generating Plant (Unit No. 1) (e) | | Coal | | 50.0 | % | | $ | 742,538 | | $ | 25,304 | | $ | 437,371 |
| | | | | | | | | | | | | | | | |
| OPCo | | | | | | | | | | | | | | |
| John E. Amos Generating Station (Unit No. 3) (a) | | Coal | | 66.67 | % | | $ | 988,870 | | $ | 6,354 | | $ | 168,933 |
| | | | | | | | | | | | | | | | |
| PSO | | | | | | | | | | | | | | |
| Oklaunion Generating Station (Unit No. 1) (g) | | Coal | | 15.6 | % | | $ | 91,275 | | $ | 1,124 | | $ | 56,160 |
| | | | | | | | | | | | | | | | |
| SWEPCo | | | | | | | | | | | | | | |
| Dolet Hills Generating Station (Unit No. 1) (h) | | Lignite | | 40.2 | % | | $ | 258,261 | | $ | 4,648 | | $ | 191,486 |
| Flint Creek Generating Station (Unit No. 1) (i) | | Coal | | 50.0 | % | | | 115,742 | | | 6,725 | | | 61,750 |
| Pirkey Generating Station (Unit No. 1) (i) | | Lignite | | 85.9 | % | | | 502,520 | | | 10,317 | | | 358,241 |
| Turk Generating Plant (j) | | Coal | | 73.33 | % | | | - | | | 971,131 | | | - |
| Total | | | | | | | $ | 876,523 | | $ | 992,821 | | $ | 611,477 |
| | | | | | | | | Company’s Share at December 31, 2009 |
| | | | | | | | | | | Construction | | |
| | | Fuel | Percent of | Utility Plant | Work in | Accumulated |
| Company | Type | Ownership | in Service | Progress | Depreciation |
| | | | | | | | | (in thousands) |
| CSPCo | | | | | | | | | | | | | | |
| W.C. Beckjord Generating Station | | Coal | | 12.5 | % | | $ | 19,400 | | $ | 120 | | $ | 8,097 |
| | (Unit No. 6) (b) | | | | | | | | | | | | | | |
| Conesville Generating Station (Unit No. 4) (c) | | Coal | | 43.5 | % | | | 300,646 | | | 3,829 | | | 44,832 |
| J.M. Stuart Generating Station (d) | | Coal | | 26.0 | % | | | 498,851 | | | 15,442 | | | 152,601 |
| Wm. H. Zimmer Generating Station (b) | | Coal | | 25.4 | % | | | 767,654 | | | 4,082 | | | 355,457 |
| Transmission | | N/A | | (f) | | | | 69,868 | | | 355 | | | 46,815 |
| Total | | | | | | | $ | 1,656,419 | | $ | 23,828 | | $ | 607,802 |
| | | | | | | | | | | | | | | | |
| PSO | | | | | | | | | | | | | | |
| Oklaunion Generating Station (Unit No. 1) (g) | | Coal | | 15.6 | % | | $ | 89,823 | | $ | 1,688 | | $ | 55,772 |
| | | | | | | | | | | | | | | | |
| SWEPCo | | | | | | | | | | | | | | |
| Dolet Hills Generating Station (Unit No. 1) (h) | | Lignite | | 40.2 | % | | $ | 255,274 | | $ | 4,212 | | $ | 188,475 |
| Flint Creek Generating Station (Unit No. 1) (i) | | Coal | | 50.0 | % | | | 115,839 | | | 4,627 | | | 60,772 |
| Pirkey Generating Station (Unit No. 1) (i) | | Lignite | | 85.9 | % | | | 496,786 | | | 7,724 | | | 350,079 |
| Turk Generating Plant (j) | | Coal | | 73.33 | % | | | - | | | 688,167 | | | - |
| Total | | | | | | | $ | 867,899 | | $ | 704,730 | | $ | 599,326 |
| (a) | Operated by APCo. |
| (b) | Operated by Duke Energy Corporation, a nonaffiliated company. |
| (c) | Operated by CSPCo. |
| (d) | Operated by The Dayton Power & Light Company, a nonaffiliated company. |
| (e) | Operated by I&M. |
| (f) | Varying percentages of ownership. |
| (g) | Operated by PSO and also jointly-owned (54.7%) by TNC. |
| (h) | Operated by Cleco Corporation, a nonaffiliated company. |
| (i) | Operated by SWEPCo. |
| (j) | Turk Generating Plant is currently under construction with a projected commercial operation date of 2012. SWEPCo jointly owns the plant with Arkansas Electric Cooperative Corporation (11.67%), East Texas Electric Cooperative (8.33%) and Oklahoma Municipal Power Authority (6.67%). Through December 2010, construction costs totaling $279 million have been billed to the other owners. |
| N/A | Not Applicable |
17. 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 provides two weeks of base pay for every year of service along with other severance benefits.
Management recorded a charge to expense in 2010 primarily related to the headcount reduction initiatives. Management does not expect additional costs to be incurred related to this initiative.
| | | Expense | | Incurred for | | | | | | | Remaining |
| | | Allocation from | | Registrant | | | | | | | Balance at |
| | | AEPSC | | Subsidiaries | | Settled | | Adjustments | | December 31, 2010 |
| | | (in thousands) |
| APCo | | $ | 20,526 | | $ | 36,399 | | $ | 51,826 | | $ | (1,373) | | $ | 3,726 |
| CSPCo | | | 11,048 | | | 21,244 | | | 30,948 | | | 110 | | | 1,454 |
| I&M | | | 12,051 | | | 32,985 | | | 41,503 | | | (1,335) | | | 2,198 |
| OPCo | | | 19,427 | | | 33,681 | | | 53,691 | | | 3,502 | | | 2,919 |
| PSO | | | 10,681 | | | 13,324 | | | 22,970 | | | 491 | | | 1,526 |
| SWEPCo | | | 12,588 | | | 17,074 | | | 28,874 | | | 965 | | | 1,753 |
These costs relate primarily to severance benefits. They are included primarily in Other Operation on the Consolidated Statements of Income and Other Current Liabilities on the Consolidated Balance Sheets.
18. UNAUDITED QUARTERLY FINANCIAL INFORMATION
In management’s opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations for interim periods. Quarterly results are not necessarily indicative of a full year’s operations because of various factors. The unaudited quarterly financial information for each Registrant Subsidiary is as follows:
| Quarterly Periods Ended: | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo | |
| | | | | (in thousands) | |
| March 31, 2010 | | | | | | | | | | | | | | | | | | |
| Total Revenues | $ | 926,623 | | $ | 517,439 | | $ | 553,056 | | $ | 861,273 | | $ | 237,755 | | $ | 342,804 | |
| Operating Income | | 157,938 | | | 98,401 | | | 87,870 | | | 181,343 | | | 22,622 | | | 43,468 | |
| Net Income | | 70,282 | | | 51,650 | | | 45,058 | | | 91,903 | | | 4,139 | | | 31,083 | |
| | | | | | | | | | | | | | | | | | | |
| June 30, 2010 | | | | | | | | | | | | | | | | | | |
| Total Revenues | $ | 703,274 | | $ | 524,104 | | $ | 509,915 | | $ | 721,964 | | $ | 327,686 | | $ | 361,467 | |
| Operating Income (a) | | 9,033 | (b) | | 97,150 | | | 42,140 | | | 89,623 | | | 39,265 | | | 43,518 | |
| Net Income (Loss) (a) | | (19,619) | (b) | | 52,116 | | | 14,602 | | | 37,548 | | | 15,489 | | | 26,705 | |
| | | | | | | | | | | | | | | | | | | |
| September 30, 2010 | | | | | | | | | | | | | | | | | | |
| Total Revenues | $ | 840,622 | | $ | 648,394 | | $ | 608,250 | | $ | 855,859 | | $ | 426,569 | | $ | 480,982 | |
| Operating Income | | 112,060 | | | 186,844 | | | 115,904 | | | 190,063 | | | 104,654 | | | 128,428 | |
| Net Income | | 50,071 | | | 107,057 | | | 62,300 | | | 100,865 | | | 55,432 | | | 81,685 | |
| | | | | | | | | | | | | | | | | | | |
| December 31, 2010 | | | | | | | | | | | | | | | | | | |
| Total Revenues | $ | 804,584 | | $ | 459,104 | | $ | 524,506 | | $ | 784,611 | | $ | 281,652 | | $ | 338,281 | |
| Operating Income | | 101,992 | | | 54,413 | (c) | | 29,001 | (d) | | 146,773 | | | 15,451 | | | 33,383 | |
| Net Income (Loss) | | 35,934 | | | 19,400 | (c) | | 4,131 | (d) | | 81,077 | | | (2,273) | | | 7,211 | |
| Quarterly Periods Ended: | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo | |
| | | | | (in thousands) | |
| March 31, 2009 | | | | | | | | | | | | | | | | | | |
| Total Revenues | $ | 786,029 | | $ | 471,736 | | $ | 567,044 | | $ | 762,715 | | $ | 295,287 | | $ | 321,802 | |
| Operating Income | | 153,898 | | | 90,533 | | | 136,570 | | | 145,077 | | | 21,872 | | | 24,993 | |
| Net Income | | 74,407 | | | 48,858 | | | 80,952 | | | 72,609 | | | 6,038 | | | 11,700 | |
| | | | | | | | | | | | | | | | | | | |
| June 30, 2009 | | | | | | | | | | | | | | | | | | |
| Total Revenues | $ | 636,112 | | $ | 507,876 | | $ | 530,416 | | $ | 678,013 | | $ | 277,141 | | $ | 340,782 | |
| Operating Income | | 85,567 | | | 150,966 | | | 91,874 | | | 133,839 | | | 50,891 | | | 48,870 | |
| Income Before Extraordinary Loss | | 29,170 | | | 84,178 | | | 48,509 | | | 63,912 | | | 24,122 | | | 35,778 | |
| Extraordinary Loss, Net of Tax | | - | | | - | | | - | | | - | | | - | | | (5,325) | (e) |
| Net Income | | 29,170 | | | 84,178 | | | 48,509 | | | 63,912 | | | 24,122 | | | 30,453 | |
| | | | | | | | | | | | | | | | | | | |
| September 30, 2009 | | | | | | | | | | | | | | | | | | |
| Total Revenues | $ | 695,673 | | $ | 556,143 | | $ | 552,267 | | $ | 765,971 | | $ | 318,555 | | $ | 414,974 | |
| Operating Income | | 83,698 | | | 167,412 | | | 100,143 | | | 186,121 | | | 81,352 | | | 83,023 | |
| Net Income | | 27,370 | | | 97,593 | | | 54,859 | | | 96,575 | | | 43,577 | | | 65,058 | |
| | | | | | | | | | | | | | | | | | | |
| December 31, 2009 | | | | | | | | | | | | | | | | | | |
| Total Revenues | $ | 758,841 | | $ | 468,818 | | $ | 535,297 | | $ | 804,875 | | $ | 233,767 | | $ | 311,744 | |
| Operating Income | | 49,362 | (f) | | 82,815 | | | 52,116 | | | 148,156 | | | 16,193 | | | 5,626 | |
| Net Income | | 24,867 | (f) | | 41,032 | | | 31,990 | | | 75,519 | | | 1,865 | | | 9,992 | |
| (a) | See Note 17 for discussion of expenses related to cost reduction initiatives recorded in the second quarter of 2010. |
| (b) | Includes a $54 million write-off of APCo’s Virginia share of the Mountaineer Carbon Capture and Storage Product Validation Facility. |
| (c) | Includes a $43 million refund provision for the 2009 Significantly Excessive Earnings Test. |
| (d) | Includes provisions for certain regulatory and legal matters. |
| (e) | See “SWEPCo Texas Restructuring” in “Extraordinary Item” section of Note 2 for discussion of the extraordinary loss recorded in the second quarter of 2009. |
| (f) | Includes a $68 million increase in storm, plant maintenance and other maintenance expenses. |
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 (a) Management’s Financial Discussion and Analysis, (b) financial statements, (c) footnotes and (d) the schedules of each individual registrant.
EXECUTIVE OVERVIEW
Economic Conditions
The Registrant Subsidiaries’ retail margins increased primarily due to successful rate proceedings in Indiana, Ohio, Oklahoma, Michigan and Virginia and higher residential and commercial demand for electricity as a result of favorable weather.
In comparison to the recessionary lows of 2009, industrial sales increased 5% in 2010 for the AEP System. During 2009, the Registrant Subsidiaries’ operations were impacted by difficult economic conditions especially their industrial sales reflecting customers’ curtailments or closures of facilities. In 2009, CSPCo’s and OPCo’s largest customer, Ormet, a major industrial customer, operated at a reduced load of approximately 330 MW and continued operations at this reduced level during 2010. In February 2009, Century Aluminum, a major industrial customer (325 MW load) of APCo, announced the curtailment of operations at its Ravenswood, WV facility.
Management forecasts slight improvement in economic conditions in 2011 for all operating companies. Industrial sales are expected to increase 4% for CSPCo and OPCo due to Ormet’s announcement of increased production in 2011. Residential growth for the Registrant Subsidiaries is expected to see slow improvement, similar to 2010.
Cost Reduction Initiatives
Due to the continued slow recovery in the U.S. economy and a corresponding negative impact on energy consumption, the AEP System implemented cost reduction initiatives in the second quarter of 2010 to reduce its workforce by 11.5% and reduce other operation and maintenance spending. Achieving these goals involved identifying process improvements, streamlining organizational designs and developing other efficiencies that will deliver additional savings. In 2010, pretax expense of $293 million was recorded related to these cost reduction initiatives. Starting with the third quarter of 2010, the Registrant Subsidiaries realized cost savings in Other Operation and Maintenance expenses on their statements of income. Management anticipates continued savings to help offset future inflationary impa cts.
LITIGATION
Potential Uninsured Losses
Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to damage to the Cook Plant and costs of replacement power in the event of a nuclear incident at the Cook Plant. Future losses or liabilities, which are not completely insured, unless recovered from customers, could have a material adverse effect on net income, cash flows and financial condition.
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.
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 engaged in the development of possible future requirements to reduce CO2 emissions to address concerns about global climate change.
Clean Air Act Requirements
The CAA establishes a comprehensive program to protect and improve the nation’s air quality and control sources of air emissions. The states implement and administer many of these programs and could impose additional or more stringent requirements. Notable developments in CAA regulatory requirements affecting the Registrant Subsidiaries’ operations are discussed briefly below.
The Federal EPA issued the Clean Air Interstate Rule (CAIR) in 2005 requiring specific reductions in SO2 and NOx emissions from power plants. In 2008, the D.C. Circuit Court of Appeals issued a decision remanding CAIR to the Federal EPA. CAIR remains in effect while a new rulemaking is conducted. Nearly all of the states in which the AEP System’s power plants are located are covered by CAIR. In July 2010, the Federal EPA issued a proposed rule (Transport Rule) to replace 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. 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 Registrant Subsidiaries 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 one 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. The time frames for and stringency of th e 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 features could accelerate unit retirements, increase capital requirements, constrain operations, decrease reliability and unfavorably impact financial condition if the increased costs are not recovered in rates or market prices. The 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 negative impact of the rule. The proposal indicates that the requirements are expected to be finalized in June 2011 and be effective January 1, 2012.
The Federal EPA issued a Clean Air Mercury Rule (CAMR) setting mercury standards for new coal-fired power plants and requiring all states to issue new state implementation plans (SIPs) 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.
Under the terms of a consent decree, the Federal EPA is required to issue final maximum achievable control technology (MACT) standards for coal and oil-fired power plants by November 2011. The Federal EPA has substantial discretion in determining how to structure the MACT standards. 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, the AEP System has approximately 5,000 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. The tim ing 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 recovery of the remaining investment in those units.
The Federal EPA issued a Clean Air Visibility Rule (CAVR), detailing how the CAA’s best available retrofit technology requirements will be applied to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants. CAVR will be implemented through individual SIPs or, if SIPs are not adequate or are not developed on schedule, through federal implementation plans (FIPs). The Federal
EPA has proposed disapproval of SIPs in a few states, and proposed more stringent control requirements for affected units in those states. If the Federal EPA takes such action in the states where the AEP System’s facilities are located, it could increase the costs of compliance, accelerate the installation of required controls, and/or force the premature retirement of existing units.
In 2009, the Federal EPA issued a final mandatory reporting rule for CO2 and other greenhouse gases covering a broad range of facilities emitting in excess of 25,000 tons of CO2 emissions per year. The Federal EPA issued a final endangerment finding for greenhouse gas emissions from new motor vehicles in 2009 and final rules limiting CO2 emissions from new motor vehicles in May 2010. The Federal EPA determined that greenhouse gas emissions from stationary sources will be subject to regulation under the CAA begi nning January 2011 and finalized its proposed scheme to streamline and phase-in regulation of stationary source CO2 emissions through the NSR prevention of significant deterioration and Title V operating permit programs through the issuance of final federal rules, SIP calls and FIPs. The Federal EPA 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 and announced a settlement agreement to issue proposed new source performance standards for 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 Federal EPA has also issued new, more stringent national ambient air quality standards (NAAQS) for SO2, NO2 and lead, and is currently reviewing the NAAQS for ozone and PM. States are in the process of evaluating the attainment status and need for additional control measures in order to attain and maintain the new NAAQS and may develop additional requirements for facilities as a result of those evaluations. Management cannot currently predict the nature, stringency or timing of those requirements.
Estimated Air Quality Environmental Investments
The CAIR, CAVR and the consent decree signed to settle the NSR litigation require significant additional investments, some of which are estimable. Management’s estimates are subject to significant uncertainties and will be affected by any changes in the outcome of several interrelated variables and assumptions, including: (a) the timing of implementation, (b) required levels of reductions, (c) methods for allocation of allowances and (d) selected compliance alternatives and their costs. These obligations may also be affected or altered by the development of new regulations described above. In short, management cannot estimate compliance costs with certainty and the actual costs to comply could differ significantly from the estimates discussed below.
The CAIR, CAVR and commitments in the consent decree will require installation of additional controls on the Registrant Subsidiaries’ power plants through 2020. The Registrant Subsidiaries plan to install additional scrubbers on 5,970 MW for SO2 control. This amount includes the installation of scrubbers on the Rockport Plant (50% I&M and 50% AEGCo). From 2011 to 2020, the following table shows the total estimated costs for environmental investment to meet these requirements including investment in scrubbers and other SO2 equipment by Registrant Subsidiary:
| | | Required |
| | | Total |
| Company | Environmental |
| | | (in millions) |
| APCo | | $ | 857 |
| CSPCo | | | 500 |
| I&M | | | 1,556 |
| OPCo | | | 1,551 |
| PSO | | | 1,186 |
| SWEPCo | | | 2,458 |
These estimates are highly uncertain due to the variability associated with: (a) the states’ implementation of these regulatory programs, including the potential for SIPs or FIPS that impose standards more stringent than CAIR or CAVR, (b) additional rulemaking activities in response to the court decisions remanding the CAIR and CAMR, (c) the actual performance of the pollution control technologies installed on each units, (d) changes in costs for new pollution controls, (e) new generating technology developments and (f) other factors. Associated operational and maintenance expenses will also increase during those years. Management cannot estimate these additional operational and maintenance costs due to the uncertainties described above, but they are expected to be significant.
The Registrant Subsidiaries will seek recovery of expenditures for pollution control technologies, replacement or additional generation and associated operating costs from customers through regulated rates. The Registrant Subsidiaries should be able to recover these expenditures through market prices in deregulated jurisdictions. If not, those costs could adversely affect future net income, cash flows and possibly financial condition.
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 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 initiate 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 managem ent alternative could be as high as $3.9 billion for units across the AEP System. Regulation of these materials as hazardous wastes would significantly increase these costs. The Registrant Subsidiaries will seek recovery of expenditures for pollution control technologies and associated costs from customers through regulated rates or market prices for electricity. If these costs are not recovered, it will have a material adverse impact on net income, cash flows and financial condition.
Global Warming
National public policy makers and regulators in the 10 states the Registrant Subsidiaries serve have conflicting views on global warming. Management is focused on taking, in the short term, actions that are seen as prudent, such as improving energy efficiency, investing in developing cost-effective and less carbon-intensive technologies and evaluating assets across a range of plausible scenarios and outcomes. Management is also an active participant in a variety of public policy discussions at state and federal levels to assure that proposed new requirements are feasible and the economies of the states served are not placed at a competitive disadvantage.
Management believes that this is a global issue and that the United States should assume a leadership role in developing a new international approach that will address growing emissions of CO2 and other greenhouse gases (generally referred to as CO2 in this discussion) from all nations, including developing countries. Management supports a reasonable approach to CO2 emission reductions that recognizes a reliable and affordable electric supply is vital to economic stability and that allows sufficient time for technology development. Management proposed to national policy makers that national and international policy for reasonable CO2 controls should involve the following principles:
| · | Comprehensiveness |
| · | Cost-effectiveness |
| · | Realistic emission reduction objectives |
| · | Reliable monitoring and verification mechanisms |
| · | Incentives to develop and deploy CO2 reduction technologies |
| · | Removal of regulatory or economic barriers to CO2 emission reductions |
| · | Recognition for early actions/investments in CO2 reduction/mitigation |
| · | Inclusion of adjustment provisions if largest emitters in developing world do not take action |
For additional information on climate change see Part I of the Annual Report under the headings entitled “Business – General – Environmental and Other Matters – Global Warming.”
While comprehensive economy-wide regulation of CO2 emissions might be achieved through future 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 discussed above.
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 al 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 and natural gas based 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 are taking steps to comply with these requirements. In order to meet these requirements and as a key part of AEP’s corporate sustainability effort, management pledged to increase wind power by an additional 2,000 MW from 2007 levels by 2011. By the end of 2010, the Registrant Subsidiaries secured, through power purchase agreements, an additional 1,111 MW of wind power. To the extent demand for renewable energy from wind power increases, it could have a positive effect on future earnings from transmission activities.
The AEP System has taken measurable, voluntary actions to reduce and offset CO2 emissions. The AEP System participates in a number of voluntary programs to monitor, mitigate and reduce CO2 emissions, but many of these programs have been discontinued due to anticipated legislative or regulatory actions. Through the end of 2009, the AEP System reduced emissions by a cumulative 94 million metric tons from adjusted baseline levels in 1998 through 2001 as a result of these voluntary actions. The AEP System’s total CO2 emissions in 2009 were 136 million metric tons. Manage ment estimates that 2010 emissions were approximately 140 million metric tons.
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 6.
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.
Global warming creates the potential for physical and financial risk. The materiality of the risks depends on whether any physical changes occur quickly or over several decades and the extent and nature of those changes. Physical risks from climate change could include changes in weather conditions. Customers' energy needs currently vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling today represent their largest energy use. To the extent weather patterns change significantly, customers' energy use could increase or decrease depending on the duration and magnitude of the changes. Increased energy use due to weather changes could require the Registrant Subsidiaries to invest in more generating assets, transmis sion and other infrastructure to serve increased load, driving the cost of electricity higher. Decreased energy use due to weather changes could affect financial condition through lower sales and decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including service interruptions and increased storm restoration
costs. The Registrant Subsidiaries may not recover all costs related to mitigating these physical and financial risks. Weather conditions outside of the AEP System’s service territory could also have an impact on revenues, either directly through changes in the patterns of off-system power purchases and sales or indirectly through demographic changes as people adapt to changing weather. The Registrant Subsidiaries buy and sell electricity depending upon system needs and market opportunities. Extreme weather conditions that create high energy demand could raise electricity prices, which would increase the cost of energy the Registrant Subsidiaries provide to customers and could provide opportunity for increased wholesale sales.
To the extent climate change impacts a region's economic health, it could also impact revenues. The Registrant Subsidiaries’ financial performance is tied to the health of the regional economies served. The price of energy, as a factor in a region's cost of living as well as an important input into the cost of goods, has an impact on the economic health of communities served. The cost of additional regulatory requirements would normally be borne by consumers through higher prices for energy and purchased goods.
FINANCIAL CONDITION
LIQUIDITY AND CAPITAL RESOURCES
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 m Parent.
The Registrant Subsidiaries and certain other companies in the AEP System entered into a 3-year credit agreement which matures in April 2011. In June 2010, the 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. This facility is fully utilized for letters of credit providing liquidity support for Pollution Control Bonds. Management intends to replace the revolving credit facility with bilateral letters of credit or refinance the bonds. Management may redeem some portion of the Pollution Control Bonds supported by the facility. As of December 31, 2010, a total of $477 million of LOCs were issued under the credit agreement. 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 | | | December 31, 2010 |
| | | | (in millions) |
| APCo | | $ | 300 | | $ | 232 |
| CSPCo | | | 230 | | | - |
| I&M | | | 230 | | | 78 |
| OPCo | | | 400 | | | 167 |
| PSO | | | 65 | | | - |
| SWEPCo | | | 230 | | | - |
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 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. AEP Credit purchases accounts receivable from the Registrant Subsidiaries. Management intends to extend or replace AEP Credit’s agreement expiring in July 2011 on or before its maturity.
BUDGETED CONSTRUCTION EXPENDITURES
The 2011 estimated construction expenditures by Registrant Subsidiary include generation, transmission and distribution related investments, as well as expenditures for compliance with environmental regulations as follows:
| | | | Budgeted Construction Expenditures |
| | Company | | Environmental | | Generation | | Transmission | | Distribution | | Other | | Total |
| | | | | (in millions) |
| | APCo | | $ | 112 | | $ | 62 | | $ | 103 | | $ | 161 | | $ | 12 | | $ | 450 |
| | CSPCo | | | 21 | | | 50 | | | 25 | | | 84 | | | 7 | | | 187 |
| | I&M | | | 1 | | | 185 | | | 29 | | | 82 | | | 8 | | | 305 |
| | OPCo | | | 50 | | | 82 | | | 37 | | | 85 | | | 10 | | | 264 |
| | PSO | | | 7 | | | 24 | | | 32 | | | 99 | | | 7 | | | 169 |
| | SWEPCo | | | 10 | | | 266 | | | 85 | | | 71 | | | 10 | | | 442 |
For 2012 through 2014, management forecasts annual construction expenditures for the AEP System to average between $2.6 billion and $3.1 billion. The projected increases are generally the result of required environmental investment to comply with Federal EPA rules and additional transmission spending. Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital. The budgeted amounts exclude AFUDC and capitalized interest. These construction expenditures will be funded through cash flows from operations and financing activities. Generally, the Regis trant Subsidiaries use cash or short-term borrowings under the money pool to fund these expenditures until long-term funding is arranged. SWEPCo’s budgeted construction expenditures include an amount for scheduled completion of the Turk Plant in 2012.
SIGNIFICANT TAX LEGISLATION
The American Recovery and Reinvestment Tax Act of 2009 provided for several new grant programs, expanded tax credits and extended the 50% bonus depreciation provision enacted in the Economic Stimulus Act of 2008. The Small Business Jobs Act, enacted in September 2010, included 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, this act extended the time for claiming bonus depreciation and increased the deduction to 100% starting in September 2010 through 2011 and dec reasing the deduction to 50% for 2012.
These enacted provisions will have no material impact on the Registrant Subsidiaries’ net income or financial condition but will have a favorable impact on their cash flows in 2011. The provisions are expected to result in material future cash flow benefits.
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 Conner 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 Conner Run received the following notices of violation and proposed assessments under the Mine Act for the quarter ended December 31, 2010:
| | | | DHLC | | CCPC | | Conner Run |
| Number of Citations for Violations of Mandatory Health or | | | | | | | | | |
| | Safety Standards under 104 * | | | 1 | | | - | | | - |
| Number of Orders Issued under 104(b) * | | | - | | | - | | | - |
| Number of Citations and Orders for Unwarrantable Failure | | | | | | | | | |
| | to Comply with Mandatory Health or Safety Standards under | | | | | | | | | |
| | 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 | | $ | 1,026 | | $ | - | | $ | - |
| Number of Mining-related Fatalities | | | - | | | - | | | - |
| | | | | | | | | | |
| * References to sections under the Mine Act | | | | | | | | | |
DHLC currently has two legal actions pending before the Mine Safety and Health Administration (MSHA) challenging four violations issued by MSHA following an employee fatality in March 2009.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES, NEW ACCOUNTING PRONOUNCEMENTS
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect reported amounts and related disclosures, including amounts related to legal matters and contingencies. Management considers an accounting estimate to be critical if:
| · | It requires assumptions to be made that were uncertain at the time the estimate was made; and |
| · | Changes in the estimate or different estimates that could have been selected could have a material effect on net income or financial condition. |
Management discusses the development and selection of critical accounting estimates as presented below with the Audit Committee of AEP’s Board of Directors and the Audit Committee reviews the disclosure relating to them.
Management believes that the current assumptions and other considerations used to estimate amounts reflected in the financial statements are appropriate. However, actual results can differ significantly from those estimates.
The sections that follow present information about the Registrant Subsidiaries’ critical accounting estimates, as well as the effects of hypothetical changes in the material assumptions used to develop each estimate.
Regulatory Accounting
Nature of Estimates Required
The financial statements of the Registrant Subsidiaries with cost-based rate-regulated operations (APCo, I&M, PSO, SWEPCo, and a portion of CSPCo and OPCo) reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.
The Registrant Subsidiaries recognize regulatory assets (deferred expenses to be recovered in the future) and regulatory liabilities (deferred future revenue reductions or refunds) for the economic effects of regulation. Specifically, the Registrant Subsidiaries match the timing of expense recognition with the recovery of such expense in regulated revenues. Likewise, they match income with the regulated revenues from their customers in the same accounting period. Liabilities are also recorded for refunds, or probable refunds, to customers that have not been made.
Assumptions and Approach Used
When incurred costs are probable of recovery through regulated rates, the Registrant Subsidiaries record them as regulatory assets on the balance sheet. Management reviews the probability of recovery at each balance sheet date and whenever new events occur. Examples of new events include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, rate of return earned on invested capital and timing and amount of assets to be recovered through regulated rates. If recovery of a regulatory asset is no longer probable, that regulatory asset is written-off as a charge against earnings. A write-off of regulatory assets may also reduce future cash flows since there will be no recovery through regulated rates.
Effect if Different Assumptions Used
A change in the above assumptions may result in a material impact on net income. Refer to Note 5 for further detail related to regulatory assets and liabilities.
Revenue Recognition – Unbilled Revenues
Nature of Estimates Required
The Registrant Subsidiaries record revenues when energy is delivered to the customer. The determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue accrual is recorded. This estimate is reversed in the following month and actual revenue is recorded based on meter readings. In accordance with the applicable state commission regulatory treatment in Arkansas, Louisiana, Oklahoma and Texas, PSO and SWEPCo do not record the fuel portion of unbilled revenue.
The changes in unbilled electricity utility revenues included in Revenue for the years ended December 31, 2010, 2009 and 2008 were as follows:
| | | Years Ended December 31, |
| Company | | 2010 | | 2009 | | 2008 |
| | | (in thousands) |
| APCo | | $ | 30,337 | | $ | 25,378 | | $ | 32,815 |
| CSPCo | | | 11,272 | | | 7,030 | | | 7,614 |
| I&M | | | 2,194 | | | 2,695 | | | 12,934 |
| OPCo | | | (1,408) | | | 5,845 | | | 4,048 |
| PSO | | | (4,159) | | | 4,415 | | | (211) |
| SWEPCo | | | (1,175) | | | (282) | | | 5,008 |
Assumptions and Approach Used
For each Registrant Subsidiary, the monthly estimate for unbilled revenues is computed as net generation less the current month’s billed KWH plus the prior month’s unbilled KWH. However, due to meter reading issues, meter drift and other anomalies, a separate monthly calculation limits the unbilled estimate within a range of values. This limiter calculation is derived from an allocation of billed KWH to the current month and previous month, on a cycle-by-cycle basis, and dividing the current month aggregated result by the billed KWH. The limits are statistically set at one standard deviation from this percentage to determine the upper and lower limits of the range. The unbilled estimate is compared to the limiter calculation and adjusted for variances exceeding the upper and low er limits.
Effect if Different Assumptions Used
Significant fluctuations in energy demand for the unbilled period, weather, line losses or changes in the composition of customer classes could impact the accuracy of the unbilled revenue estimate. A 1% change in the limiter calculation when it is outside the range would increase or decrease unbilled revenues by 1% of the accrued unbilled revenues.
Accounting for Derivative Instruments
Nature of Estimates Required
Management considers fair value techniques, valuation adjustments related to credit and liquidity and judgments related to the probability of forecasted transactions occurring within the specified time period to be critical accounting estimates. These estimates are considered significant because they are highly susceptible to change from period to period and are dependent on many subjective factors.
Assumptions and Approach Used
The Registrant Subsidiaries measure the fair values of derivative instruments and hedge instruments accounted for using MTM accounting based on exchange prices and broker quotes. If a quoted market price is not available, the fair value is estimated based on the best market information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and other assumptions. Fair value estimates, based upon the best market information available, involve uncertainties and matters of significant judgment. These uncertainties include projections of macroeconomic trends and future commodity prices, including supply and demand levels and future price volatility.
The Registrant Subsidiaries reduce fair values by estimated valuation adjustments for items such as discounting, liquidity and credit quality. Liquidity adjustments are calculated by utilizing bid/ask spreads to estimate the potential fair value impact of liquidating open positions over a reasonable period of time. Credit adjustments on risk management contracts are calculated using estimated default probabilities and recovery rates relative to the counterparties or counterparties with similar credit profiles and contractual netting agreements. With respect to hedge accounting, management assesses hedge effectiveness and evaluates a forecasted transaction’s probability of occurrence within the specified time period as provided in the original hedge documentation.
Effect if Different Assumptions Used
There is inherent risk in valuation modeling given the complexity and volatility of energy markets. Therefore, it is possible that results in future periods may be materially different as contracts settle.
The probability that hedged forecasted transactions will not occur by the end of the specified time period could change operating results by requiring amounts currently classified in Accumulated Other Comprehensive Income (Loss) to be classified into operating income.
For additional information regarding derivatives, hedging and fair value measurements, see Notes 10 and 11. See “Fair Value Measurements of Assets and Liabilities” section of Note 1 for fair value calculation policy.
Long-Lived Assets
Nature of Estimates Required
In accordance with the requirements of “Property, Plant and Equipment” accounting guidance, the Registrant Subsidiaries evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such assets may not be recoverable or the assets meet the held for sale criteria. The Registrant Subsidiaries utilize a group composite method of depreciation to estimate the useful lives of long-lived assets as approved by their regulators. The evaluations of long-lived held and used assets may result from abandonments, significant decreases in the market price of an asset, a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, a significant adverse change in legal factors or in the business climat e that could affect the value of an asset, as well as other economic or operations analyses. If the carrying amount is not recoverable, the Registrant Subsidiary records an impairment to the extent that the fair value of the asset is less than its book value. For assets held for sale, an impairment is recognized if the expected net sales price is less than its book value. For regulated assets, an impairment charge could be offset by the establishment of a regulatory asset, if rate recovery is probable. For nonregulated assets, any impairment charge is recorded against earnings.
Assumptions and Approach Used
The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, the Registrant Subsidiaries estimate fair value using various internal and external valuation methods including cash flow projections or other market indicators of fair value such as bids received, comparable sales or independent appraisals. The Registrant Subsidiaries perform depreciation studies to determine composite depreciation rates and related lives which are subject to periodic review by state regulatory commissions. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.
Effect if Different Assumptions Used
In connection with the evaluation of long-lived assets in accordance with the requirements of “Property, Plant and Equipment” accounting guidance, the fair value of the asset can vary if different estimates and assumptions would have been used in the applied valuation techniques. The estimate for depreciation rates takes into account the past history of interim capital replacements and the amount of salvage expected. In cases of impairment, the best estimate of fair value was made using valuation methods based on the most current information at that time. Fluctuations in realized sales proceeds versus the estimated fair value of the asset are generally due to a variety of factors including, but not limited to, differences in subsequent market conditions, the level of bidder interest, timin g and terms of the transactions and management’s analysis of the benefits of the transaction.
Pension and Other Postretirement Benefits
AEP maintains a qualified, defined benefit pension plan (Qualified Plan), which covers substantially all nonunion and certain union employees, and unfunded, nonqualified supplemental plans (Nonqualified Plans) to provide benefits in excess of amounts permitted under the provisions of the tax law to be paid to participants in the Qualified Plans (collectively the Pension Plans). Additionally, AEP entered into individual employment contracts with certain current and retired executives that provide additional retirement benefits as a part of the Nonqualified Plans. AEP also sponsors other postretirement benefit plans to provide medical and life insurance benefits for retired employees (Postretirement Plans). The Pension Plans and Postretirement Plans are collectively the Plans.
The Registrant Subsidiaries participate in the Plans. The Plans cover all employees who meet eligibility requirements.
For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Investments Held in Trust for Future Liabilities” and “Fair Value Measurements of Assets and Liabilities” sections of Note 1. See Note 8 for information regarding costs and assumptions for employee retirement and postretirement benefits.
The following table shows the net periodic cost (credit) for the years ended December 31, 2010, 2009 and 2008 by Registrant Subsidiary for the Plans:
| | | | | | | | | | | | | | | | | | | |
| Pension Plans | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| 2010 | | $ | 15,818 | | $ | 5,945 | | $ | 20,138 | | $ | 13,756 | | $ | 5,439 | | $ | 7,096 |
| 2009 | | | 10,459 | | | 2,752 | | | 13,939 | | | 8,267 | | | 3,080 | | | 4,831 |
| 2008 | | | 3,337 | | | (1,398) | | | 7,283 | | | 1,277 | | | 2,033 | | | 3,742 |
| | | | | | | | | | | | | | | | | | | |
| Other Postretirement Benefit Plans | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| 2010 | | $ | 19,048 | | $ | 8,250 | | $ | 13,857 | | $ | 15,862 | | $ | 7,443 | | $ | 7,574 |
| 2009 | | | 24,231 | | | 10,554 | | | 17,433 | | | 20,557 | | | 9,134 | | | 9,453 |
| 2008 | | | 14,896 | | | 6,041 | | | 9,765 | | | 11,357 | | | 5,581 | | | 5,539 |
| | | | | | | | | | | | | | | | | | | |
The net periodic benefit cost is calculated based upon a number of actuarial assumptions, including expected long-term rates of return on the Plans’ assets. In developing the expected long-term rate of return assumption for 2011, management evaluated input from actuaries and investment consultants, including their reviews of asset class return expectations as well as long-term inflation assumptions. Management also considered historical returns of the investment markets. Management anticipates that the investment managers employed for the Plans will invest the assets to generate future returns averaging 7.75% for the Qualified Plan and 7.5% for the Postretirement Plans.
The expected long-term rate of return on the Plans’ assets is based on AEP’s targeted asset allocation and expected investment returns for each investment category. Assumptions for the Plans are summarized in the following table:
| | | | Other Postretirement |
| | Pension Plans | | Benefit Plans |
| | | | Assumed/ | | | | Assumed/ |
| | 2011 | | Expected | | 2011 | | Expected |
| | Target | | Long-Term | | Target | | Long-Term |
| | Asset | | Rate of | | Asset | | Rate of |
| | Allocation | | Return | | Allocation | | Return |
| Equity | 50 | % | | 9.00 | % | | 66 | % | | 9.00 | % |
| Real Estate | 5 | % | | 7.60 | % | | - | % | | - | % |
| Debt Securities | 39 | % | | 5.75 | % | | 32 | % | | 5.75 | % |
| Other Investments | 5 | % | | 10.50 | % | | - | % | | - | % |
| Cash and Cash Equivalents | 1 | % | | 3.00 | % | | 2 | % | | 3.00 | % |
| Total | 100 | % | | | | | 100 | % | | | |
Management regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation. Management believes that 7.75% for the Pension Plan and 7.5% for the Postretirement Plans are reasonable long-term rates of return on the Plans’ assets despite the recent market volatility. The Pension Plan’s assets had an actual gain of 13.4% and 17.1% for the years ended December 31, 2010 and 2009, respectively. The Postretirement Plans’ assets had an actual gain of 11.3% and 23.7% for the years ended December 31, 2010 and 2009, respectively. Management will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the assumptions as necessary.
AEP bases the determination of pension expense or income on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of December 31, 2010, AEP had cumulative losses of approximately $285 million that remain to be recognized in the calculation of the m arket-related value of assets. These unrecognized net actuarial losses will result in increases in the future pension costs depending on several factors,
including whether such losses at each measurement date exceed the corridor in accordance with “Compensation – Retirement Benefits” accounting guidance. See the table below for the amount of cumulative losses by Registrant Subsidiary.
The method used to determine the discount rate that AEP utilizes for determining future obligations is a duration-based method in which a hypothetical portfolio of high quality corporate bonds similar to those included in the Moody’s Aa bond index is constructed with a duration matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan. The discount rate at December 31, 2010 under this method was 5.05% for the Qualified Plan, 4.95% for the Nonqualified Plans and 5.25% for the Postretirement Plans. Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on the Pension Plans’ assets of 7.75%, a discount rate of 5.05% and 4.95% and various other assumptions, management estimates t hat the pension costs by Registrant Subsidiary for all pension plans will approximate the amounts in the following table. Based on an expected rate of return on the OPEB plans’ assets of 7.5%, a discount rate of 5.25% and various other assumptions, management estimates Postretirement Plan costs by Registrant Subsidiary will approximate the amounts in the following tables:
| | | | | | | | | | | | | | | | | | | |
| Cumulative Losses | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| Deferred Asset Loss | | $ | 37,859 | | $ | 20,714 | | $ | 33,345 | | $ | 38,291 | | $ | 15,767 | | $ | 16,582 |
| | | | | | | | | | | | | | | | | | | |
| Pension Plans | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| 2011 | | $ | 17,433 | | $ | 8,659 | | $ | 17,412 | | $ | 14,295 | | $ | 9,811 | | $ | 10,175 |
| 2012 | | | 20,219 | | | 11,656 | | | 18,984 | | | 17,177 | | | 12,681 | | | 13,166 |
| 2013 | | | 24,887 | | | 13,516 | | | 24,207 | | | 21,549 | | | 11,755 | | | 11,949 |
| | | | | | | | | | | | | | | | | | | |
| Other Postretirement Benefit Plans | | APCo | | CSPCo | | I&M | | OPCo | | PSO | | SWEPCo |
| | | (in thousands) |
| 2011 | | $ | 14,762 | | $ | 5,791 | | $ | 11,635 | | $ | 12,251 | | $ | 4,445 | | $ | 4,845 |
| 2012 | | | 13,561 | | | 5,475 | | | 10,186 | | | 11,679 | | | 4,270 | | | 4,654 |
| 2013 | | | 12,012 | | | 5,193 | | | 9,731 | | | 11,172 | | | 4,124 | | | 4,492 |
| | | | | | | | | | | | | | | | | | | |
Future actual costs will depend on future investment performance, changes in future discount rates and various other factors related to each Registrant Subsidiary’s populations participating in the Plans. The actuarial assumptions used may differ materially from actual results. The effects of a 50 basis point change to selective actuarial assumptions are included in the “Effect if Different Assumptions Used” section below.
The value of AEP’s Pension Plans’ assets increased to $3.9 billion at December 31, 2010 from $3.4 billion at December 31, 2009 primarily due to a $500 million contribution. During 2010, the Qualified Plan paid $465 million in benefits to plan participants and the nonqualified plans paid $15 million in benefits. The value of AEP’s Postretirement Plans’ assets increased to $1.5 billion at December 31, 2010 from $1.3 billion at December 31, 2009 primarily due to investment gains and contributions. The Postretirement Plans paid $142 million in benefits to plan participants during 2010. See Note 8 for complete details by Registrant Subsidiary.
Nature of Estimates Required
The Registrant Subsidiaries participate in AEP sponsored pension and other retirement and postretirement benefit plans in various forms covering all employees who meet eligibility requirements. These benefits are accounted for under “Compensation” and “Plan Accounting” accounting guidance. The measurement of pension and postretirement benefit obligations, costs and liabilities is dependent on a variety of assumptions.
Assumptions and Approach Used
The critical assumptions used in developing the required estimates include the following key factors:
| · | Rate of compensation increase |
| · | Cash balance crediting rate |
| · | Health care cost trend rate |
| · | Expected return on plan assets |
Other assumptions, such as retirement, mortality and turnover, are evaluated periodically and updated to reflect actual experience.
Effect if Different Assumptions Used
The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates, longer or shorter life spans of participants or higher or lower lump sum versus annuity payout elections by plan participants. These differences may result in a significant impact to the amount of pension and postretirement benefit expense recorded. If a 50 basis point change were to occur for the following assumptions, the approximate effect on the financial statements would be as follows:
| | APCo | | | | Other Postretirement |
| | | | Pension Plans | | Benefit Plans |
| | | | +0.5% | | -0.5% | | +0.5% | | -0.5% |
| | | | (in thousands) |
| | Effect on December 31, 2010 Benefit Obligations | | | | | | | | | | | | |
| | Discount Rate | | $ | (32,159) | | $ | 35,286 | | $ | (22,728) | | $ | 25,268 |
| | Compensation Increase Rate | | | 1,166 | | | (1,086) | | | 3 | | | (3) |
| | Cash Balance Crediting Rate | | | 4,904 | | | (4,116) | | | N/A | | | N/A |
| | Health Care Cost Trend Rate | | | N/A | | | N/A | | | 19,401 | | | (17,875) |
| | | | | | | | | | | | | | |
| | Effect on 2010 Periodic Cost | | | | | | | | | | | | |
| | Discount Rate | | | (2,751) | | | 3,006 | | | (2,366) | | | 2,655 |
| | Compensation Increase Rate | | | 479 | | | (439) | | | 113 | | | (106) |
| | Cash Balance Crediting Rate | | | 1,412 | | | (1,259) | | | N/A | | | N/A |
| | Health Care Cost Trend Rate | | | N/A | | | N/A | | | 3,257 | | | (2,910) |
| | Expected Return on Plan Assets | | | (2,697) | | | 2,697 | | | (1,050) | | | 1,054 |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | CSPCo | | | | Other Postretirement |
| | | | Pension Plans | | Benefit Plans |
| | | | +0.5% | | -0.5% | | +0.5% | | -0.5% |
| | | | (in thousands) |
| | Effect on December 31, 2010 Benefit Obligations | | | | | | | | | | | | |
| | Discount Rate | | $ | (15,931) | | $ | 17,396 | | $ | (9,880) | | $ | 11,002 |
| | Compensation Increase Rate | | | 624 | | | (577) | | | 2 | | | (2) |
| | Cash Balance Crediting Rate | | | 1,746 | | | (1,507) | | | N/A | | | N/A |
| | Health Care Cost Trend Rate | | | N/A | | | N/A | | | 8,300 | | | (7,630) |
| | | | | | | | | | | | | | |
| | Effect on 2010 Periodic Cost | | | | | | | | | | | | |
| | Discount Rate | | | (1,494) | | | 1,632 | | | (991) | | | 1,110 |
| | Compensation Increase Rate | | | 260 | | | (239) | | | 51 | | | (48) |
| | Cash Balance Crediting Rate | | | 767 | | | (684) | | | N/A | | | N/A |
| | Health Care Cost Trend Rate | | | N/A | | | N/A | | | 1,413 | | | (1,259) |
| | Expected Return on Plan Assets | | | (1,465) | | | 1,465 | | | (472) | | | 474 |
| | | | | | | | | | | | | | |
| | I&M | | | | Other Postretirement |
| | | | Pension Plans | | Benefit Plans |
| | | | +0.5% | | -0.5% | | +0.5% | | -0.5% |
| | | | (in thousands) |
| | Effect on December 31, 2010 Benefit Obligations | | | | | | | | | | | | |
| | Discount Rate | | $ | (29,382) | | $ | 32,383 | | $ | (16,618) | | $ | 18,564 |
| | Compensation Increase Rate | | | 1,499 | | | (1,388) | | | 3 | | | (3) |
| | Cash Balance Crediting Rate | | | 5,229 | | | (4,475) | | | N/A | | | N/A |
| | Health Care Cost Trend Rate | | | N/A | | | N/A | | | 14,170 | | | (12,858) |
| | | | | | | | | | | | | | |
| | Effect on 2010 Periodic Cost | | | | | | | | | | | | |
| | Discount Rate | | | (2,365) | | | 2,584 | | | (1,482) | | | 1,651 |
| | Compensation Increase Rate | | | 412 | | | (378) | | | 88 | | | (82) |
| | Cash Balance Crediting Rate | | | 1,213 | | | (1,082) | | | N/A | | | N/A |
| | Health Care Cost Trend Rate | | | N/A | | | N/A | | | 2,275 | | | (2,014) |
| | Expected Return on Plan Assets | | | (2,316) | | | 2,316 | | | (812) | | | 815 |
| | | | | | | | | | | | | | |
| | OPCo | | | | Other Postretirement |
| | | | Pension Plans | | Benefit Plans |
| | | | +0.5% | | -0.5% | | +0.5% | | -0.5% |
| | | | (in thousands) |
| | Effect on December 31, 2010 Benefit Obligations | | | | | | | | | | | | |
| | Discount Rate | | $ | (30,215) | | $ | 33,096 | | $ | (21,157) | | $ | 23,654 |
| | Compensation Increase Rate | | | 1,050 | | | (968) | | | 2 | | | (2) |
| | Cash Balance Crediting Rate | | | 4,262 | | | (3,562) | | | N/A | | | N/A |
| | Health Care Cost Trend Rate | | | N/A | | | N/A | | | 18,318 | | | (16,812) |
| | | | | | | | | | | | | | |
| | Effect on 2010 Periodic Cost | | | | | | | | | | | | |
| | Discount Rate | | | (2,656) | | | 2,902 | | | (2,041) | | | 2,287 |
| | Compensation Increase Rate | | | 462 | | | (424) | | | 104 | | | (98) |
| | Cash Balance Crediting Rate | | | 1,363 | | | (1,215) | | | N/A | | | N/A |
| | Health Care Cost Trend Rate | | | N/A | | | N/A | | | 2,899 | | | (2,583) |
| | Expected Return on Plan Assets | | | (2,602) | | | 2,602 | | | (964) | | | 968 |
| | | | | | | | | | | | | | |
| | PSO | | | | Other Postretirement |
| | | | Pension Plans | | Benefit Plans |
| | | | +0.5% | | -0.5% | | +0.5% | | -0.5% |
| | | | (in thousands) |
| | Effect on December 31, 2010 Benefit Obligations | | | | | | | | | | | | |
| | Discount Rate | | $ | (11,647) | | $ | 12,698 | | $ | (7,330) | | $ | 8,191 |
| | Compensation Increase Rate | | | 673 | | | (608) | | | 3 | | | (3) |
| | Cash Balance Crediting Rate | | | 3,529 | | | (3,303) | | | N/A | | | N/A |
| | Health Care Cost Trend Rate | | | N/A | | | N/A | | | 6,518 | | | (5,434) |
| | | | | | | | | | | | | | |
| | Effect on 2010 Periodic Cost | | | | | | | | | | | | |
| | Discount Rate | | | (1,129) | | | 1,234 | | | (639) | | | 712 |
| | Compensation Increase Rate | | | 197 | | | (180) | | | 39 | | | (37) |
| | Cash Balance Crediting Rate | | | 578 | | | (516) | | | N/A | | | N/A |
| | Health Care Cost Trend Rate | | | N/A | | | N/A | | | 998 | | | (883) |
| | Expected Return on Plan Assets | | | (1,104) | | | 1,104 | | | (361) | | | 363 |
| | | | | | | | | | | | | | |
| | SWEPCo | | | | Other Postretirement |
| | | | Pension Plans | | Benefit Plans |
| | | | +0.5% | | -0.5% | | +0.5% | | -0.5% |
| | | | (in thousands) |
| | Effect on December 31, 2010 Benefit Obligations | | | | | | | | | | | | |
| | Discount Rate | | $ | (11,515) | | $ | 12,552 | | $ | (8,411) | | $ | 9,411 |
| | Compensation Increase Rate | | | 666 | | | (598) | | | 4 | | | (4) |
| | Cash Balance Crediting Rate | | | 4,295 | | | (4,035) | | | N/A | | | N/A |
| | Health Care Cost Trend Rate | | | N/A | | | N/A | | | 7,541 | | | (6,338) |
| | | | | | | | | | | | | | |
| | Effect on 2010 Periodic Cost | | | | | | | | | | | | |
| | Discount Rate | | | (1,126) | | | 1,230 | | | (708) | | | 789 |
| | Compensation Increase Rate | | | 196 | | | (180) | | | 43 | | | (40) |
| | Cash Balance Crediting Rate | | | 577 | | | (514) | | | N/A | | | N/A |
| | Health Care Cost Trend Rate | | | N/A | | | N/A | | | 1,106 | | | (978) |
| | Expected Return on Plan Assets | | | (1,100) | | | 1,100 | | | (400) | | | 402 |
N/A Not Applicable
Nuclear Trust Funds
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.
I&M maintains trust funds 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 these trust funds as Spent Nuclear Fuel and Decommissioning Trusts on its Consolidated Balance Sheets. I&M records these securities at fair value. Management utilizes the trustee’s external pricing service to estimate the fair value of the underlying investments held in these trusts. I&M’s investment managers review and validate the pric es utilized by the trustee to determine fair value. Management performs valuation testing to verify the fair values of the securities. Management receives audit reports of the trustee’s operating controls and valuation processes. See “Investments Held in Trust for Future Liabilities” section of Note 1 and “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11.
NEW 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, 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 financial position.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT 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” section. Also, see Note 10 – Derivatives and Hedging and Note 11 – 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:
| | MTM Risk Management Contract Net Assets (Liabilities) |
| | Year Ended December 31, 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 | | (28,148) |
| 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 | | (217) |
| Changes in Fair Value Due to Market Fluctuations During the Period (c) | | 65 |
| Changes in Fair Value Allocated to Regulated Jurisdictions (d) | | 9,985 |
| Total MTM Risk Management Contract Net Assets | | 26,882 |
| Cash Flow Hedge Contracts | | 11,494 |
| Collateral Deposits | | 14,420 |
| Total MTM Derivative Contract Net Assets at December 31, 2010 | $ | 52,796 |
| | | | |
| 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 | | (17,265) |
| Fair Value of New Contracts at Inception When Entered During the Period (a) | | 9,434 |
| 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 | | (441) |
| Changes in Fair Value Due to Market Fluctuations During the Period (c) | | 4,013 |
| Changes in Fair Value Allocated to Regulated Jurisdictions (d) | | (3,092) |
| Total MTM Risk Management Contract Net Assets | | 18,264 |
| Cash Flow Hedge Contracts | | (337) |
| Collateral Deposits | | 10,289 |
| Total MTM Derivative Contract Net Assets at December 31, 2010 | $ | 28,216 |
| | | | |
| 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 | | 96 |
| 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 | | (74) |
| Changes in Fair Value Due to Market Fluctuations During the Period (c) | | (19) |
| Changes in Fair Value Allocated to Regulated Jurisdictions (d) | | (12) |
| Total MTM Risk Management Contract Net Assets | | (378) |
| Cash Flow Hedge Contracts | | 13,692 |
| Collateral Deposits | | 44 |
| Total MTM Derivative Contract Net Assets at December 31, 2010 | $ | 13,358 |
| | | | |
| 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 | | (2,059) |
| 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 | | (128) |
| Changes in Fair Value Due to Market Fluctuations During the Period (c) | | (25) |
| Changes in Fair Value Allocated to Regulated Jurisdictions (d) | | (2,382) |
| Total MTM Risk Management Contract Net Assets | | (2,958) |
| Cash Flow Hedge Contracts | | 128 |
| Collateral Deposits | | 72 |
| Total MTM Derivative Contract Net Assets at December 31, 2010 | $ | (2,758) |
| (a) | Reflects fair value on primarily long-term 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) | Relates to the net gains (losses) of those contracts that are not reflected on the Consolidated Statements of Income. These net gains (losses) are recorded as regulatory liabilities/assets. |
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) |
| December 31, 2010 |
| | | | | | | | | | | | | |
| APCo | | | | | | | | | | | |
| | | 2011 | | 2012-2014 | | 2015+ | | Total |
| | | (in thousands) |
| Level 1 (a) | $ | 33 | | $ | - | | $ | - | | $ | 33 |
| Level 2 (b) | | 3,588 | | | 14,518 | | | 241 | | | 18,347 |
| Level 3 (c) | | 2,053 | | | 1,909 | | | 1,169 | | | 5,131 |
| Total | | 5,674 | | | 16,427 | | | 1,410 | | | 23,511 |
| Dedesignated Risk Management | | | | | | | | | | | |
| | Contracts (d) | | 1,779 | | | 1,592 | | | - | | | 3,371 |
| Total MTM Risk Management | | | | | | | | | | | |
| | Contract Net Assets | $ | 7,453 | | $ | 18,019 | | $ | 1,410 | | $ | 26,882 |
| | | | | | | | | | | | | |
| OPCo | | | | | | | | | | | |
| | | 2011 | | 2012-2014 | | 2015+ | | Total |
| | | (in thousands) |
| Level 1 (a) | $ | 23 | | $ | - | | $ | - | | $ | 23 |
| Level 2 (b) | | 1,637 | | | 10,454 | | | 170 | | | 12,261 |
| Level 3 (c) | | 1,455 | | | 1,330 | | | 823 | | | 3,608 |
| Total | | 3,115 | | | 11,784 | | | 993 | | | 15,892 |
| Dedesignated Risk Management | | | | | | | | | | | |
| | Contracts (d) | | 1,252 | | | 1,120 | | | - | | | 2,372 |
| Total MTM Risk Management | | | | | | | | | | | |
| | Contract Net Assets | $ | 4,367 | | $ | 12,904 | | $ | 993 | | $ | 18,264 |
| PSO | | | | | | | | |
| | | 2011 | | 2012-2014 | | Total |
| | | (in thousands) |
| Level 1 (a) | $ | - | | $ | - | | $ | - |
| Level 2 (b) | | (432) | | | 53 | | | (379) |
| Level 3 (c) | | (1) | | | 2 | | | 1 |
| Total MTM Risk Management | | | | | | | | |
| | Contract Net Assets | $ | (433) | | $ | 55 | | $ | (378) |
| | | | | | | | | | |
| SWEPCo | | | | | | | | |
| | | 2011 | | 2012-2014 | | Total |
| | | (in thousands) |
| Level 1 (a) | $ | - | | $ | - | | $ | - |
| Level 2 (b) | | (3,055) | | | 95 | | | (2,960) |
| Level 3 (c) | | 2 | | | - | | | 2 |
| Total MTM Risk Management | | | | | | | | |
| | Contract Net Assets | $ | (3,053) | | $ | 95 | | $ | (2,958) |
| (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 December 31, 2010, 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:
VaR Model
| | Twelve Months Ended December 31, |
| | 2010 | | 2009 |
| Company | | End | | High | | Average | | Low | | End | | High | | Average | | Low |
| | (in thousands) |
| APCo | | $ | 124 | | $ | 659 | | $ | 193 | | $ | 71 | | $ | 275 | | $ | 699 | | $ | 333 | | $ | 151 |
| OPCo | | | 100 | | | 545 | | | 161 | | | 54 | | | 201 | | | 530 | | | 244 | | | 113 |
| PSO | | | 3 | | | 70 | | | 15 | | | 1 | | | 10 | | | 34 | | | 12 | | | 4 |
| SWEPCo | | | 6 | | | 93 | | | 21 | | | 2 | | | 16 | | | 49 | | | 18 | | | 6 |
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 report 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 December 31, 2010 and 2009, the estimated EaR on the Registrant Subsidiaries’ debt portfolio was as follows:
| | | December 31, |
| Company | | 2010 | | 2009 |
| | | (in thousands) |
| APCo | | $ | 1,165 | | $ | 1,837 |
| CSPCo | | | 178 | | | 216 |
| I&M | | | 274 | | | 227 |
| OPCo | | | 926 | | | 1,373 |
| PSO | | | 658 | | | 119 |
| SWEPCo | | | 1,027 | | | 305 |
