Why did reported net income rise in 1998 even though operating earnings fell?

The comparison is distorted by a one-time 1997 extraordinary loss of $109.4 million from the UK windfall tax on Yorkshire Electricity. Income before that item actually declined 14%, from $620 million ($3.28/share) to $536 million ($2.81/share), due to Cook Plant restart costs, a $30 million Ionica write-down, severance charges, and weak weather-driven sales.

What is the financial impact of the Cook Nuclear Plant outage?

Both Cook units have been shut since September 1997. Restart was pushed back in January 1999 pending expanded engineering reviews, and a new schedule is not expected until June 1999. Restart costs were $6M in 1997 and $78M in 1998, and are running about $12M per month. A $65M regulatory asset for replacement power costs is recorded, and a March 1999 Indiana settlement would refund $55M to customers while allowing deferral of certain costs. Without cost recovery, results would be materially harmed.

How is AEP's strategy changing, and what are the risks?

AEP is expanding into non-regulated international and domestic energy businesses, including CitiPower, Yorkshire, Pacific Hydro, China generation, and gas midstream and trading operations. These acquisitions raised debt and lowered the equity ratio, and trading and foreign investments add market, credit, and currency risk. Management says the regulated utility base and cost advantages remain the core, but the outcome of these investments is uncertain.

What is the status of the CSW merger and how could it affect shareholders?

AEP and Central and South West agreed in December 1997 to a stock-for-stock merger that would make CSW shareholders receive 0.6 AEP shares per share, valued at about $6.6 billion. Approvals have been received from the Arkansas PSC and the NRC, with others still pending, including FERC hearings starting June 1999, Texas hearings in April 1999, and the Oklahoma and Kentucky proceedings. The merger agreement terminates December 31, 1999 unless extended, and management expects closing in Q4 1999.

What environmental and regulatory costs could weigh on AEP's future earnings?

The NOx SIP Call and Section 126 petitions could require roughly $1.2 billion in capital spending across the AEP System, with Phase II Clean Air Act compliance (about $90M, $69M already spent) due January 2000. Potential Kyoto-driven CO2 limits and the Muskingum mine closure (with a $45M provision) add further cost pressure. These costs are only recoverable if passed through to customers or allowed as stranded costs, so unrecovered amounts would reduce earnings.

AEP 10-K FY1998 Annual Report — Revenue, Net Income, EPS

01—Abstract

Summary

Summary of the 10-K filed March 29, 1999. Cited figures are marked; the original filing is the authoritative source.

American Electric Power (AEP) filed its 1998 Form 10-K as a combined filing covering AEP and its operating subsidiaries (AEGCo, APCo, CSPCo, I&M, KEPCo, OPCo).

AEP reported 1998 net income of $536 million^a, or $2.81 per share, up 5% from $511 million ($2.70 per share) in 1997. That increase is largely the result of a $109 million extraordinary loss in 1997 from the UK windfall tax on its Yorkshire investment. Income before the extraordinary item fell 14% from $620 million ($3.28 per share), pressured by restart costs for the shut-down Cook Nuclear Plant, a $30 million write-down of Yorkshire's investment in Ionica, staff-reduction severance, and mild weather.

Operating revenues rose 8% to $6.35 billion^b, driven by wholesale trading, purchased-power resales, and transmission services. AEP is pursuing a strategy of growth beyond its regulated utility base. In 1998 it spent roughly $1.1 billion to acquire CitiPower, a Melbourne distribution utility, and about $340 million for Equitable Resources' midstream gas assets in Louisiana and Texas.

It also holds a 50% interest in Yorkshire Electricity, a 20% stake in Pacific Hydro, and a 70% stake in Chinese generation units. Balance sheet leverage rose sharply: long-term debt increased to $6.8 billion^c from $5.1 billion, and the common equity ratio fell to 40.3% from 45.5%. Management continues to target a payout-ratio reduction, which was 85.4% in 1998.

Key risks for investors include the extended, unplanned outage at the Cook Plant (restart now delayed, with incremental costs near $12 million^d per month), a pending merger with Central and South West Corporation expected to close in late 1999, possible federal disallowance of about $316 million in COLI interest deductions, and approximately $1.2 billion in estimated NOx compliance capital spending. Regulatory transitions in Virginia, Ohio, and Michigan toward retail competition add uncertainty about stranded-cost recovery.

02—Key points

Key Highlights

1998 net income of $536 million ($2.81/share), up 5% reported, but income before the 1997 extraordinary item fell 14% to $620M → $536M
Operating revenues rose 7.9% to $6.35 billion, led by wholesale (+25.9%) and transmission (+61.7%) growth
Major 1998 acquisitions: CitiPower (Australia, ~$1.1B) and midstream gas assets (~$340M), increasing long-term debt to $6.8B
Cook Nuclear Plant has been offline since September 1997; restart is delayed and incremental restart costs run about $12M/month
Pending CSW merger (0.6 AEP shares per CSW share, ~$6.6B valuation) expected to close in Q4 1999, subject to multiple regulatory approvals
Contingent liability of up to $316M (incl. interest) if IRS disallows COLI interest deductions for 1991–1998; no provision recorded
Common equity ratio fell to 40.3% from 45.5%; dividend held at $2.40/share with a payout ratio of 85.4%

03—Questions

Frequently Asked Questions

Why did reported net income rise in 1998 even though operating earnings fell?
The comparison is distorted by a one-time 1997 extraordinary loss of $109.4 million from the UK windfall tax on Yorkshire Electricity. Income before that item actually declined 14%, from $620 million ($3.28/share) to $536 million ($2.81/share), due to Cook Plant restart costs, a $30 million Ionica write-down, severance charges, and weak weather-driven sales.
What is the financial impact of the Cook Nuclear Plant outage?
Both Cook units have been shut since September 1997. Restart was pushed back in January 1999 pending expanded engineering reviews, and a new schedule is not expected until June 1999. Restart costs were $6M in 1997 and $78M in 1998, and are running about $12M per month. A $65M regulatory asset for replacement power costs is recorded, and a March 1999 Indiana settlement would refund $55M to customers while allowing deferral of certain costs. Without cost recovery, results would be materially harmed.
How is AEP's strategy changing, and what are the risks?
AEP is expanding into non-regulated international and domestic energy businesses, including CitiPower, Yorkshire, Pacific Hydro, China generation, and gas midstream and trading operations. These acquisitions raised debt and lowered the equity ratio, and trading and foreign investments add market, credit, and currency risk. Management says the regulated utility base and cost advantages remain the core, but the outcome of these investments is uncertain.
What is the status of the CSW merger and how could it affect shareholders?
AEP and Central and South West agreed in December 1997 to a stock-for-stock merger that would make CSW shareholders receive 0.6 AEP shares per share, valued at about $6.6 billion. Approvals have been received from the Arkansas PSC and the NRC, with others still pending, including FERC hearings starting June 1999, Texas hearings in April 1999, and the Oklahoma and Kentucky proceedings. The merger agreement terminates December 31, 1999 unless extended, and management expects closing in Q4 1999.
What environmental and regulatory costs could weigh on AEP's future earnings?
The NOx SIP Call and Section 126 petitions could require roughly $1.2 billion in capital spending across the AEP System, with Phase II Clean Air Act compliance (about $90M, $69M already spent) due January 2000. Potential Kyoto-driven CO2 limits and the Muskingum mine closure (with a $45M provision) add further cost pressure. These costs are only recoverable if passed through to customers or allowed as stranded costs, so unrecovered amounts would reduce earnings.

04—Continue

← View all 10-K filings