Exhibit 99.3
Management’s Narrative Analysis of Results of Operations
The Results of Operations discussion for Detroit Edison is presented in accordance with General Instruction I (2) (a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).
Factors impacting income:Our earnings decreased $96 million to $150 million in 2004 from $246 million in 2003. 2003 earnings decreased $110 million from the $356 million earned in 2002. As subsequently discussed, these results primarily reflect reduced gross margins and increased operation and maintenance expenses.
(in Millions) | 2004 | 2003 | 2002 | |||||||||
Operating Revenues | $ | 3,568 | $ | 3,695 | $ | 4,054 | ||||||
Fuel and Purchased Power | 885 | 939 | 1,074 | |||||||||
Gross Margin | 2,683 | 2,756 | 2,980 | |||||||||
Operation and Maintenance | 1,394 | 1,352 | 1,271 | |||||||||
Depreciation and Amortization | 523 | 473 | 577 | |||||||||
Taxes Other Than Income | 249 | 257 | 273 | |||||||||
Operating Income | 517 | 674 | 859 | |||||||||
Other (Income) and Deductions | 303 | 277 | 325 | |||||||||
Income Tax Provision | 64 | 145 | 178 | |||||||||
Income before Accounting Change | 150 | 252 | 356 | |||||||||
Cumulative Effect of Accounting Change | — | (6 | ) | — | ||||||||
Net Income | $ | 150 | $ | 246 | $ | 356 | ||||||
Operating Income as a Percent of Operating Revenues | 14 | % | 18 | % | 21 | % |
Gross marginsdeclined $73 million during 2004 and declined $224 million in 2003. Operating revenues decreased primarily as a result of increased electric Customer Choice penetration whereby Detroit Edison lost 18% of retail sales in 2004 and 12% of such sales during 2003 as retail customers chose to purchase power from alternative suppliers.
The loss in 2004 revenues was partially offset by increased base rates resulting from the interim and final rate orders. Revenues in 2004 and 2003 were both adversely impacted by reduced cooling demand resulting from mild summer weather. In addition, operating revenues and fuel and purchased power costs decreased in 2004 and 2003 reflecting a $1.27 per megawatt hour (MWh) (8%) decline in fuel and purchased power costs during 2004 and a $.64 per MWh (4%) decline during 2003. The loss of retail sales under the electric Customer Choice program also resulted in lower purchase power requirements, as well as excess power capacity that was sold in the wholesale market. Under the 2004 interim and final rate orders, revenues from selling excess power reduce the level of
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recoverable fuel and purchased power costs and therefore do not impact margins associated with uncapped customers. The rate orders also lowered Power Supply Cost Recovery (PSCR) revenues, which were partially offset by the previously mentioned increased base rate and transition charge revenues. Since fuel and purchased power costs are a pass-through with the reinstatement of the PSCR in 2004, a decrease affects both revenues and fuel and purchased power costs but does not affect margins or earnings associated with uncapped customers. The decrease in fuel and purchased power costs is attributable to lower priced purchases and the use of a more favorable power supply mix driven by higher generation output. The favorable mix is due to lower purchases, driven by lost sales under the electric Customer Choice program. The comparison was also affected by higher costs associated with substitute power purchased to meet customer demand during the August 2003 blackout. We were required to purchase additional power during the 36-day period it took for our generation fleet to return to pre-blackout capacity.
2004 | 2003 | 2002 | ||||||||||||||||||||||
Electric Sales and Use | ||||||||||||||||||||||||
(in Thousands of MWh) | ||||||||||||||||||||||||
Retail | 40,379 | 43,672 | 48,346 | |||||||||||||||||||||
Wholesale and Other | 8,569 | 5,600 | 6,128 | |||||||||||||||||||||
48,948 | 49,272 | 54,474 | ||||||||||||||||||||||
Internal Use and Line Loss | 3,574 | 3,248 | 3,651 | |||||||||||||||||||||
52,522 | 52,520 | 58,125 | ||||||||||||||||||||||
Power Generated and Purchased (in Thousands of MWh) | ||||||||||||||||||||||||
Power Plant Generation | ||||||||||||||||||||||||
Fossil | 39,432 | 75 | % | 38,052 | 72 | % | 39,017 | 67 | % | |||||||||||||||
Nuclear (Fermi 2) | 8,440 | 16 | 8,114 | 16 | 9,301 | 16 | ||||||||||||||||||
47,872 | 91 | 46,166 | 88 | 48,318 | 83 | |||||||||||||||||||
Purchased Power | 4,650 | 9 | 6,354 | 12 | 9,807 | 17 | ||||||||||||||||||
System Output | 52,522 | 100 | % | 52,520 | 100 | % | 58,125 | 100 | % | |||||||||||||||
Average Unit Cost ($/MWh) | ||||||||||||||||||||||||
Generation (1) | $ | 12.98 | $ | 12.89 | $ | 12.53 | ||||||||||||||||||
Purchased Power (2) | $ | 37.06 | $ | 41.73 | $ | 39.16 | ||||||||||||||||||
Overall Average Unit Cost | $ | 15.11 | $ | 16.38 | $ | 17.02 | ||||||||||||||||||
(1) | Represents fuel costs associated with power plants. | |
(2) | Includes amounts associated with hedging activities. |
2004 | 2003 | 2002 | ||||||||||
Electric Deliveries | ||||||||||||
(in Thousands of MWh) | ||||||||||||
Residential | 15,081 | 15,074 | 15,958 | |||||||||
Commercial | 13,425 | 15,942 | 18,395 | |||||||||
Industrial | 11,472 | 12,254 | 13,590 | |||||||||
Wholesale | 2,197 | 2,241 | 2,249 | |||||||||
Other | 401 | 402 | 403 | |||||||||
42,576 | 45,913 | 50,595 | ||||||||||
Electric Choice | 9,245 | 6,193 | 2,967 | |||||||||
Electric Choice – Self Generations* | 595 | 1,088 | 543 | |||||||||
Total Electric Deliveries | 52,416 | 53,194 | 54,105 | |||||||||
* | Represents deliveries for self generators who have purchased power from alternative energy suppliers to supplement their power requirements. |
Operation and maintenanceexpense increased $42 million in 2004 and increased $81 million in 2003. The 2004 increase reflects costs associated with maintaining our generation fleet, including costs of scheduled and forced
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plant outages. Additionally, the increase in 2004 is due to incremental costs associated with the implementation of our DTE2 project, a Company-wide initiative to improve existing processes and to implement new core information systems, including finance, human resources, supply chain and work management. The 2003 increase was impacted by restoration costs associated with three catastrophic storms, the August 2003 blackout and a $22 million pre-tax loss from the sale of our steam heating business. Operation and maintenance expense in both years includes higher employee pension and health care benefit costs due to financial market performance, discount rates and health care trend rates. Additionally, we increased reserves for uncollectible accounts receivable, reflecting high past due amounts attributable to economic conditions and we accrued refunds due from the Midwest Independent System Operator (MISO) related 2004 and 2003 associated with transmission services.
Depreciation and amortizationexpense increased $50 million in 2004 and decreased $104 million in 2003. The variations reflect the income effect of recording regulatory assets, which lowered depreciation and amortization expenses. The regulatory asset deferrals totaled $107 million in 2004 and $153 million in 2003, representing net stranded costs and other costs we believe are recoverable under Public Act (PA) 141.
Other income and deductionsexpense increased $26 million in 2004 and decreased $48 million in 2003. The 2004 increase is primarily due to lower income associated with recording a return on regulatory assets, as well as costs associated with addressing the structural issues of PA 141. The 2003 decrease is attributable to lower interest expenses and increased interest income. Interest expense reflects lower borrowing levels and rates, and interest income includes the accrual of carrying charges on environmental-related regulatory assets.
Outlook– Future operating results are expected to vary as a result of external factors such as regulatory proceedings, new legislation, changes in market prices of power, coal and gas, plant performance, changes in economic conditions, weather, the levels of customer participation in the electric Customer Choice program and the severity and frequency of storms.
We expect cash flows and operating performance will continue to be at risk due to the electric Customer Choice program until the issues associated with this program are addressed. We will accrue as regulatory assets our unrecovered generation-related fixed costs (stranded costs) due to electric Customer Choice that we believe are recoverable under Michigan legislation and MPSC orders. We have addressed certain issues of the electric Customer Choice program in our February 2005 rate restructuring proposal. We cannot predict the outcome of these matters.
We experienced numerous catastrophic storms over the past few years. The effect of the storms on annual earnings was partially offset by storm insurance. We have been unable to obtain storm insurance at economical rates and as
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a result, we do not anticipate having insurance coverage at levels that would significantly offset unplanned expenses from ice storms, tornadoes, or high winds that damage our distribution infrastructure.
In conjunction with DTE Energy’s sale of the transmission assets of ITC in February 2003, the Federal Energy Regulatory Commission (FERC) froze ITC’s transmission rates through December 2004. It is expected that annual rate adjustments pursuant to a formulistic pricing mechanism beginning in January 2005 will result in an estimated increase in Detroit Edison’s transmission expense of $50 million annually. Additionally, in a proceeding before the FERC, several Midwest utilities seek to recover transmission revenues lost as a result of a FERC order modifying the pricing of transmission service in the Midwest. Detroit Edison estimates that its potential obligation as a result of this proceeding could be $2.2 million per month from December 2004 through March 2005 and $1 million per month from April 2005 through March 2006. Detroit Edison is expected to incur an additional $15 million in 2005 for charges related to the implementation of Midwest Independent Transmission System Operator’s open market. As previously discussed, Detroit Edison received rate orders in 2004 that allow for the recovery of increased transmission expenses through the PSCR mechanism.
See Note 4 – Regulatory Matters.
CUMULATIVE EFFECT OF ACCOUNTING CHANGES
As required by U.S. generally accepted accounting principles, on January 1, 2003, we adopted a new accounting rule for asset retirement obligations. The cumulative effect of adopting this new accounting rule reduced 2003 earnings by $6 million. See Note 2 for further discussion.
Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Detroit Edison has commodity price risk arising from market price fluctuations in conjunction with the anticipated purchase of electricity to meet its obligations during periods of peak demand. To limit our exposure to commodity price fluctuations, we have entered into electricity option contracts. Commodity price risk is limited due to the PSCR mechanism (Note 1).
See Note 12 – Financial and Other Derivative Instruments for further discussion.
Interest Rate Risk
Detroit Edison is subject to interest rate risk in connection with the issuance of debt securities. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR). We estimate that if interest rates were 10% higher or lower, the fair value of long-term debt at December 31, 2004 would decrease $189 million and increase $200 million, respectively.
Credit Risk
We purchase and sell electricity from and to numerous companies operating in the steel, automotive, energy, retail and other industries. A number of customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We have negotiated or are currently involved in negotiations with each of the companies, or their successor companies, that have filed for bankruptcy protection. We regularly review contingent matters and record provisions for amounts considered probable of loss. We believe our accrued amounts are adequate for probable losses. The final resolution of these matters is not expected to have a material effect on our financial statements in the period they are resolved.
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