Why did AEP report a net loss in 2002 but only a small profit in 2003?

The 2002 net loss of $519 million reflected large impairments, goodwill write-downs and discontinued-operations losses on U.K. assets, SEEBOARD, CitiPower and Eastex. In 2003 the company took similarly large charges (about $1.4 billion pre-tax) but earnings from continuing utility operations improved, and a $193 million after-tax net gain from accounting changes (mainly the removal of accumulated cost-of-removal balances under SFAS 143) offset much of the discontinued-operations loss. Investors should focus on the $522 million from continuing operations, which is a cleaner measure than the $110 million headline.

What is the dividend outlook after the 2003 cut?

The quarterly dividend was reduced from $0.60 to $0.35 per share in June 2003, lowering annualized cash outflows by roughly $395 million. Management said the cut supports debt reduction and balance-sheet strengthening. The filing does not commit to a future dividend level, and the 2003 total of $1.65 per share still exceeded earnings per share before discontinued operations, so dividend sustainability depends on continued utility earnings growth and completion of planned asset sales.

How exposed is AEP to the Texas stranded-cost and true-up outcome?

TCC has elected to value its 4,497 MW of Texas generation through sale proceeds, and the difference from book value will be determined in the 2004 true-up proceeding, currently expected around April 2005. The company recorded a $938 million regulatory asset and a $480 million wholesale capacity auction true-up asset. Fuel reconciliation disputes could also reduce recovery: the ALJ recommended a $140 million TCC fuel disallowance and a $205 million over-recovery credit. Any shortfall in recovery would reduce earnings and cash flow.

What are the largest legal and regulatory risks disclosed?

The most significant items are the Federal EPA and state New Source Review enforcement case (civil penalties are not estimable and could require additional pollution control spending), the CFTC complaint alleging manipulation of natural gas prices, shareholder securities and ERISA suits, Enron's challenge to HPL's Bammel storage arrangements and claims totaling roughly $125 million and $93 million, and the requirement to join PJM by October 2004 under the FERC order. Management says it cannot predict outcomes for most of these matters.

How much capital spending and environmental investment is expected?

Construction expenditures are forecast at about $5.8 billion for 2004-2006, with roughly 80% expected to be funded internally. Pending SO2, NOx and mercury rules proposed in January 2004 could require about $1.7 billion of additional capital by 2010 plus $150 million of incremental operating costs, and about $1.2 billion of additional scrubber investment is planned over four years. Management states these costs should be recoverable through regulated rates or market prices, but recovery is not assured.

AEP 10-K FY2003 Annual Report — Revenue, Net Income, EPS

01—Abstract

Summary

Summary of the 10-K filed March 11, 2004. Cited figures are marked; the original filing is the authoritative source.

American Electric Power (AEP) filed its combined 2003 Form 10-K (dated March 10, 2004) covering the parent holding company and ten operating subsidiaries.

The year was a transition year: AEP reported 2003 net income of $110 million^a, or $0.29 per share, down from a 2002 net loss of $519 million, but this headline is depressed by large one-time charges. Income before discontinued operations, extraordinary items and accounting changes rose to $522 million ($1.35 per share) from $485 million, helped by higher wholesale earnings, lower impairments and a $392 million reduction in operations and maintenance expense. Discontinued operations lost $605 million, driven largely by the planned sale of U.K. generation and Louisiana Intrastate Gas, and total 2003 impairments and related charges were about $1.4 billion pre-tax across assets, investments and discontinued operations.

Management's strategy centers on refocusing on regulated utilities (about 38,000 MW of domestic generation, 39,000 miles of transmission and roughly 22,000 employees) while exiting non-core investments. Planned dispositions include the 4,000 MW U.K. business, the 4,497 MW Texas generation portfolio held by TCC, Louisiana gas pipelines, four domestic IPPs, and a coal business. Financing actions were significant: AEP issued about $1.1 billion^b of common equity, cut the quarterly dividend to $0.35 from $0.60 (reducing annual cash outflows by roughly $395 million), reduced short-term debt by $2.8 billion and maintained investment-grade ratings after 2003 downgrades to Baa3/BBB/BBB at the senior unsecured level.

Key risks remain substantial. The filing discloses an unresolved Clean Air Act New Source Review enforcement case, a CFTC complaint alleging natural gas price manipulation, shareholder and ERISA class actions, Enron bankruptcy claims (including a challenge to Bammel storage rights), Texas true-up proceedings that will determine stranded-cost recovery (including a $480 million^c wholesale capacity true-up asset), and pending PJM/RTO integration deadlines. Forward capital needs are about $5.8 billion for 2004-2006, largely environmental (SO2, NOx and mercury compliance could cost roughly $1.7 billion more by 2010).

02—Key points

Key Highlights

Net income of $110 million ($0.29/share) versus a $519 million net loss in 2002; before discontinued operations and accounting changes, earnings rose to $522 million ($1.35/share) from $485 million.
Discontinued operations lost $605 million after tax, mainly from U.K. generation ($507 million loss) and Louisiana Intrastate Gas, reflecting the decision to exit non-core assets.
Total 2003 impairments and related charges were about $1.4 billion pre-tax, including $650 million in asset impairments (e.g., $300 million HPL/Gas, $258 million Juniper power facility) and $938 million in Texas generation write-downs offset by a regulatory asset.
Utility Operations earnings rose to $1.218 billion ($3.17/share), while Gas Operations (-$290 million) and Other Investments (-$277 million) continued to drag results.
Common dividend cut to $0.35 per quarter from $0.60 in June 2003; about $1.1 billion of new common equity was issued in March 2003 to reduce debt.
Senior unsecured ratings were lowered to Baa3 (Moody's), BBB (S&P) and BBB (Fitch) during 2003, with all agencies at stable outlook; debt-to-capital covenant was 58.8% versus a 67.5% limit.
Major open matters include the Federal EPA New Source Review enforcement suit, a CFTC natural gas manipulation complaint, Enron bankruptcy litigation, and the 2004 Texas true-up proceeding for TCC and TNC stranded costs.

03—Questions

Frequently Asked Questions

Why did AEP report a net loss in 2002 but only a small profit in 2003?
The 2002 net loss of $519 million reflected large impairments, goodwill write-downs and discontinued-operations losses on U.K. assets, SEEBOARD, CitiPower and Eastex. In 2003 the company took similarly large charges (about $1.4 billion pre-tax) but earnings from continuing utility operations improved, and a $193 million after-tax net gain from accounting changes (mainly the removal of accumulated cost-of-removal balances under SFAS 143) offset much of the discontinued-operations loss. Investors should focus on the $522 million from continuing operations, which is a cleaner measure than the $110 million headline.
What is the dividend outlook after the 2003 cut?
The quarterly dividend was reduced from $0.60 to $0.35 per share in June 2003, lowering annualized cash outflows by roughly $395 million. Management said the cut supports debt reduction and balance-sheet strengthening. The filing does not commit to a future dividend level, and the 2003 total of $1.65 per share still exceeded earnings per share before discontinued operations, so dividend sustainability depends on continued utility earnings growth and completion of planned asset sales.
How exposed is AEP to the Texas stranded-cost and true-up outcome?
TCC has elected to value its 4,497 MW of Texas generation through sale proceeds, and the difference from book value will be determined in the 2004 true-up proceeding, currently expected around April 2005. The company recorded a $938 million regulatory asset and a $480 million wholesale capacity auction true-up asset. Fuel reconciliation disputes could also reduce recovery: the ALJ recommended a $140 million TCC fuel disallowance and a $205 million over-recovery credit. Any shortfall in recovery would reduce earnings and cash flow.
What are the largest legal and regulatory risks disclosed?
The most significant items are the Federal EPA and state New Source Review enforcement case (civil penalties are not estimable and could require additional pollution control spending), the CFTC complaint alleging manipulation of natural gas prices, shareholder securities and ERISA suits, Enron's challenge to HPL's Bammel storage arrangements and claims totaling roughly $125 million and $93 million, and the requirement to join PJM by October 2004 under the FERC order. Management says it cannot predict outcomes for most of these matters.
How much capital spending and environmental investment is expected?
Construction expenditures are forecast at about $5.8 billion for 2004-2006, with roughly 80% expected to be funded internally. Pending SO2, NOx and mercury rules proposed in January 2004 could require about $1.7 billion of additional capital by 2010 plus $150 million of incremental operating costs, and about $1.2 billion of additional scrubber investment is planned over four years. Management states these costs should be recoverable through regulated rates or market prices, but recovery is not assured.

04—Continue

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