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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549


FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended June 30, 2003

Commission file number 1-11607

DTE ENERGY COMPANY
(Exact name of registrant as specified in its charter)

     
Michigan   38-3217752
(State or other jurisdiction of   (I.R.S. Employer
incorporation or organization)   Identification No.)
     
2000 2nd Avenue, Detroit, Michigan   48226-1279
(Address of principal executive offices)   (Zip Code)

313-235-4000
(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 (Exchange Act) during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

     
Yes x   No o

Indicate by check mark whether the registrant is an accelerated filer as defined in Rule 12b-2 of the Exchange Act.

     
Yes x   No o

At July 31, 2003, 168,247,689 shares of DTE Energy’s Common Stock, substantially all held by non-affiliates, were outstanding.



 


TABLE OF CONTENTS

DEFINITIONS
FORWARD-LOOKING STATEMENTS
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Item 4. Controls and Procedures
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statement of Operations
Consolidated Statement of Financial Position
Consolidated Statement of Cash Flows
Consolidated Statement of Changes in Shareholders’ Equity and Comprehensive Income
Notes to Consolidated Financial Statements
CONSOLIDATING STATEMENTS OF OPERATIONS
CONSOLIDATING STATEMENTS OF OPERATIONS
CONSOLIDATING STATEMENTS OF OPERATIONS
CONSOLIDATING STATEMENTS OF OPERATIONS
CONSOLIDATING STATEMENTS OF FINANCIAL POSITION
CONSOLIDATING STATEMENTS OF FINANCIAL POSITION
CONSOLIDATING STATEMENTS OF CASH FLOWS (UNAUDITED)
CONSOLIDATING STATEMENTS OF CASH FLOWS (UNAUDITED)
Independent Accountants’ Report
PART II — OTHER INFORMATION
Item 1. Legal Proceedings
Item 2. Changes in Securities and Use of Proceeds
Item 3. Defaults Upon Senior Securities
Item 4. Submission of Matters to a Vote of Securities Holders
Item 5. Other Information
Item 6. Exhibits and Reports on Form 8-K
SIGNATURE
DTE Annual & Long Term Incentive Program
Awareness Letter of Deloitte & Touche LLP
302 Certification of Chief Executive Officer
302 Certification of Chief Financial Officer
906 Certification of Chief Executive Officer
906 Certification of Chief Financial Officer


Table of Contents

DTE ENERGY COMPANY

QUARTERLY REPORT ON FORM 10-Q
QUARTER ENDED JUNE 30, 2003

TABLE OF CONTENTS

             
        PAGE  
       
 
DEFINITIONS
    3  
 
       
FORWARD-LOOKING STATEMENTS
    5  
 
       
PART I — FINANCIAL INFORMATION
       
 
       
 
Item 1. Financial Statements
       
 
       
   
Consolidated Statement of Operations
    20  
 
       
   
Consolidated Statement of Financial Position
    21  
 
       
   
Consolidated Statement of Cash Flows
    23  
 
       
   
Consolidated Statement of Changes in Shareholders’ Equity and Comprehensive Income
    24  
 
       
   
Notes to Consolidated Financial Statements
    25  
 
       
   
Independent Accountants’ Report
    46  
 
       
 
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
    6  
 
       
 
Item 3. Quantitative and Qualitative Disclosures About Market Risk
    18  
 
       
 
Item 4. Controls and Procedures
    19  
 
       
PART II — OTHER INFORMATION
       
 
       
 
Item 1. Legal Proceedings
    47  
 
       
 
Item 2. Changes in Securities and Use of Proceeds
    47  
 
       
 
Item 3. Defaults Upon Senior Securities
    47  
 
       
 
Item 4. Submission of Matters to a Vote of Securities Holders
    47  
 
       
 
Item 5. Other Information
    48  
 
       
 
Item 6. Exhibits and Reports on Form 8-K
    49  
 
       
SIGNATURE
    50  

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DEFINITIONS

     
Company   DTE Energy Company and subsidiary companies
     
Customer Choice   Statewide initiatives giving customers in Michigan the option to choose alternative suppliers for electricity and gas.
     
Detroit Edison   The Detroit Edison Company (a wholly owned subsidiary of DTE Energy Company) and subsidiary companies
     
DTE Energy   DTE Energy Company, the parent of Detroit Edison and Enterprises
     
EPA   United States Environmental Protection Agency
     
FERC   Federal Energy Regulatory Commission
     
GCR   A gas cost recovery mechanism authorized by the MPSC that was reinstated by MichCon in January 2002, permitting MichCon to pass the cost of natural gas to its customers.
     
ITC   International Transmission Company (until February 28, 2003, a wholly owned subsidiary of DTE Energy Company)
     
MCN Energy   MCN Energy Group Inc. and subsidiary companies that were merged into Enterprises
     
MichCon   Michigan Consolidated Gas Company and subsidiary companies
     
MPSC   Michigan Public Service Commission
     
MWh   Megawatthour
     
PLR   A private letter ruling issued by the Internal Revenue Service interpreting a statute or administrative rule and its application to a particular set of facts and circumstances, typically addressing an unusual or complex transaction.
     
PSCR   A power supply cost recovery mechanism authorized by the MPSC that allowed Detroit Edison to recover through rates its fuel, fuel-related and purchased power electric expenses. The clause was suspended under Michigan’s restructuring legislation signed into law June 5, 2000, which lowered and froze electric customer rates.
     
Section 29 Tax Credits   Tax credits authorized under Section 29 of the Internal Revenue Code that are designed to stimulate investment in and development of alternate fuel sources.
     
Securitization   Detroit Edison financed specific stranded costs at lower interest rates through the sale of rate reduction bonds by a wholly owned special purpose entity, the Detroit Edison Securitization Funding LLC.
     
SFAS   Statement of Financial Accounting Standards

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Stranded Costs   Costs incurred by utilities in order to serve customers in a regulated environment that are not expected to be recoverable if customers switch to alternative suppliers of electricity and gas.
     
Synfuels   The synthetic fuel process involves chemically modifying and binding particles of coal to produce a fuel that is used for power generation and coke production.

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FORWARD-LOOKING STATEMENTS

Certain information presented herein includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements involve certain risks and uncertainties that may cause actual future results to differ materially from those contemplated, projected, estimated or budgeted in such forward-looking statements. There are many factors that may impact forward-looking statements including, but not limited to, the following:

  the effects of weather and other natural phenomena on operations and sales to customers;
 
  economic climate and growth in the geographic areas where we do business;
 
  environmental issues, including changes in the climate, and regulations;
 
  nuclear regulations and risks associated with nuclear operations;
 
  ability to utilize Section 29 tax credits, sell interests in facilities producing such credits or the resolution of the IRS review of chemical change at synthetic fuel facilities;
 
  implementation of Customer Choice programs;
 
  implementation of electric and gas utility restructuring in Michigan;
 
  employee relations;
 
  unplanned outages;
 
  capital market conditions and access to capital markets and other financing efforts which can be affected by credit agency ratings;
 
  the timing and extent of changes in interest rates;
 
  the level of borrowings;
 
  changes in the cost of fuel, purchased power and natural gas;
 
  effects of competition;
 
  impact of FERC and MPSC proceedings and regulations;
 
  contributions to earnings by non-regulated businesses;
 
  changes in federal or state tax laws and their interpretations, including the code, regulations, rulings, court proceedings and audits;
 
  ability to recover costs through rate increases;
 
  property insurance;
 
  the cost of protecting assets against or damage due to terrorism; and
 
  changes in accounting standards and financial reporting regulations.

New factors emerge from time to time. We cannot predict what factors may arise or how such factors may cause our results to differ materially from those contained in any forward-looking statement. Any forward-looking statement speaks only as of the date on which such statement is made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events.

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DTE ENERGY COMPANY
MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

RESULTS OF OPERATIONS

We had a loss of $39 million in the 2003 second quarter, or $.23 per diluted share, compared to income of $68 million, or $.42 per diluted share, for the 2002 second quarter. For the six-month period, our income was $116 million, or $.69 per diluted share, compared to income of $268 million, or $1.66 per diluted share, for the comparable 2002 period. The comparability of earnings was impacted by the sale of our transmission business, International Transmission Company (ITC), and the adoption of two new accounting rules in the 2003 first quarter. Upon selling ITC in February 2003, we classified this business as a discontinued operation. Earnings from this discontinued business for the 2003 six-month period include a $67 million net of tax gain recorded on the sale. As required by generally accepted accounting principles, on January 1, 2003 we adopted new accounting rules for asset retirement obligations and energy trading activities as discussed in Note 2. The cumulative effect of adopting these new accounting rules reduced earnings for the 2003 six-month period by $27 million.

Excluding discontinued operations and the cumulative effect of accounting changes, our loss from continuing operations for the 2003 second quarter was $37 million or $.22 per diluted share, compared to income of $61 million, or $.38 per diluted share, in the 2002 second quarter. For the 2003 six-month period, we had income from continuing operations of $71 million, or $.42 per diluted share, compared to income of $253 million, or $1.57 per diluted share, for the comparable 2002 period. The table below details several significant items impacting comparability, which reduced earnings by $107 million, or $.64 per diluted share, and $25 million, or $.15 per diluted share, for the second quarter of 2003 and 2002, respectively. Significant items also impacted the 2003 and 2002 six-month periods reducing earnings by $177 million, or $1.05 per diluted share, and $14 million, or $.08 per diluted share, respectively. Also impacting the comparison were higher non-regulated earnings, effects of weather, higher pension and health care costs, and increased fuel, purchased power and gas costs.

                                   
      Three Months Ended     Six Months Ended  
      June 30     June 30  
     
   
 
(in Millions, Except Per Share Amounts)   2003     2002     2003     2002  
   
   
   
   
 
Significant Items Impacting Comparability
                               
Energy Resources - Margins resulting from accounting change (1)
  $     $     $ 16     $  
Energy Distribution - Loss on sale of steam business (2)
                (14 )      
Energy Gas - Disallowance of gas costs (3)
                (17 )      
Corporate -
                               
 
Contribution to DTE Energy Foundation (4)
                (10 )      
 
Tax credit driven normalization (5)
    (107 )     (25 )     (152 )     (14 )
 
 
   
   
   
 
Net Income (Loss)
  $ (107 )   $ (25 )   $ (177 )   $ (14 )
 
 
   
   
   
 
Diluted Earnings (Loss) Per Share
  $ (.64 )   $ (.15 )   $ (1.05 )   $ (.08 )
 
 
   
   
   
 


(1)   DTE Energy realized additional margins as a result of the change in accounting for energy trading activities (Note 2).
 
(2)   The Detroit Edison steam heating business was sold in January 2003 (Note 3).
 
(3)   MichCon established a reserve for the potential disallowance of procured gas costs (Note 4).
 
(4)   DTE Energy used a portion of the proceeds from the ITC sale to fund the DTE Energy Foundation.
 
(5)   Quarterly tax adjustment to normalize DTE Energy’s effective tax rate. Annual results are not affected.

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As discussed in DTE Energy’s 2002 Annual Report on Form 10-K, we operate our business through nine reportable segments. The following tables and related discussion depict the operations of each of these segments.

                                       
          Three Months Ended     Six Months Ended  
          June 30     June 30  
         
   
 
(in Millions)   2003     2002     2003     2002  
   
   
   
   
 
Net Income (Loss)
                               
Energy Resources
                               
   
Regulated — Power Generation
  $ 46     $ 56     $ 71     $ 117  
 
 
   
   
   
 
   
Non-regulated
                               
     
Energy Services
    76       30       127       62  
     
Energy Marketing & Trading
    (15 )     (5 )     29       13  
     
Other
    1       (1 )     1       (1 )
 
 
   
   
   
 
   
Total Non-regulated
    62       24       157       74  
 
 
   
   
   
 
 
    108       80       228       191  
 
 
   
   
   
 
Energy Distribution
                               
   
Regulated — Power Distribution
    (16 )     18       (20 )     46  
   
Non-regulated
    (5 )     (4 )     (9 )     (7 )
 
 
   
   
   
 
 
    (21 )     14       (29 )     39  
 
 
   
   
   
 
Energy Gas
                               
   
Regulated — Gas Distribution
    (8 )     (1 )     51       53  
   
Non-regulated
    6       8       14       14  
 
 
   
   
   
 
 
    (2 )     7       65       67  
 
 
   
   
   
 
Corporate & Other
    (122 )     (40 )     (193 )     (44 )
 
 
   
   
   
 
Income from Continuing Operations
                               
 
Regulated
    22       73       102       216  
 
Non-regulated (1)
    (59 )     (12 )     (31 )     37  
 
 
   
   
   
 
 
    (37 )     61       71       253  
 
 
   
   
   
 
Discontinued Operations
    (2 )     7       72       15  
Cumulative Effect of Accounting Changes
                (27 )      
 
 
   
   
   
 
Net Income (Loss)
  $ (39 )   $ 68     $ 116     $ 268  
 
 
   
   
   
 
Diluted Earnings (Loss) per Share
                               
 
Regulated
  $ .13     $ .44     $ .61     $ 1.34  
 
Non-regulated (1)
    (.35 )     (.06 )     (.19 )     .23  
 
 
   
   
   
 
Income (Loss) from Continuing Operations
    (.22 )     .38       .42       1.57  
Discontinued Operations
    (.01 )     .04       .43       .09  
Cumulative Effect of Accounting Changes
                (.16 )      
 
 
   
   
   
 
Net Income (Loss)
  $ (.23 )   $ .42     $ .69     $ 1.66  
 
 
   
   
   
 


(1)   Includes Corporate & Other

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ENERGY RESOURCES

Power Generation

The power generation plants of Detroit Edison comprise our regulated power generation business. Detroit Edison’s numerous fossil plants, hydroelectric pumped storage plant and its nuclear plant generate electricity that is sold principally throughout Michigan and the Midwest to residential, commercial, industrial and wholesale customers.

Power Generation earnings declined $10 million during the 2003 second quarter and $46 million in the 2003 six-month period reflecting lower gross margins driven by decreased cooling demand due to mild weather and lost margins from customers participating in the electric Customer Choice program. As a result of the electric Customer Choice program, Detroit Edison lost 12% of retail sales in 2003. To partially offset the impact of these lost margins, Detroit Edison recorded a $6 million increase in regulatory assets in both the 2003 first and second quarters representing stranded costs that are recoverable under Michigan legislation. The lower earnings were also attributed to higher fuel unit costs, higher employee pension and health care benefit costs and expenses due to the timing of planned reliability and maintenance work done to improve the production and availability of the generation fleet. Operation and maintenance expense in the 2003 second quarter was favorably affected by adjustments recorded that reduced accruals for employee incentive awards due to expected lower 2003 operating performance. Depreciation and amortization expenses reflect the income effect of recording regulatory assets representing net stranded costs and the deferral of other costs recoverable under Public Act 141.

                                 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
   
   
 
(in Millions)   2003     2002     2003     2002  
 
   
   
   
 
Operating Revenues
  $ 589     $ 660     $ 1,206     $ 1,277  
Fuel and Purchased Power
    224       243       465       443  
 
 
   
   
   
 
Gross Margin
    365       417       741       834  
Operation and Maintenance
    158       175       341       312  
Depreciation and Amortization
    61       76       134       161  
Taxes other than Income
    38       36       81       77  
 
 
   
   
   
 
Operating Income
    108       130       185       284  
Other (Income) and Deductions
    37       44       77       105  
Income Tax Provision
    25       30       37       62  
 
 
   
   
   
 
Net Income
  $ 46     $ 56     $ 71     $ 117  
 
 
   
   
   
 
Operating Income as a Percent of Operating Revenues
    18 %     20 %     15 %     22 %

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System output and average fuel and purchased power costs were as follows:

                                   
      Three Months Ended     Six Months Ended  
      June 30     June 30  
     
   
 
(in Thousands of MWh)   2003     2002     2003     2002  
   
   
   
   
 
Power generated and purchased
                               
Power plant generation
                               
 
Fossil
    9,207       9,519       18,341       18,630  
 
Nuclear
    1,301       2,334       3,549       4,624  
 
 
   
   
   
 
 
    10,508       11,853       21,890       23,254  
Purchased power
    1,843       2,178       3,731       3,818  
 
 
 
   
   
   
 
System output
    12,351       14,031       25,621       27,072  
 
 
   
   
   
 
Average unit cost ($/MWh)
                               
Generation (1)
  $ 13.56     $ 12.64     $ 13.42     $ 12.41  
 
 
   
   
   
 
Purchased power (2)
  $ 35.26     $ 37.77     $ 34.48     $ 34.48  
 
 
   
   
   
 
Overall Average Unit Cost
  $ 16.80     $ 16.17     $ 17.00     $ 15.29  
 
 
   
   
   
 


(1)   Represents fuel costs associated with power plants.
 
(2)   Includes hedging activities.

Outlook — We expect electric restructuring to continue resulting in increased customer choice in the retail electric generation business. As a result of customers choosing to participate in the electric Customer Choice program, Detroit Edison lost 6% of retail sales in 2002 and estimates losing up to 13% of such sales in 2003. Unrecovered generation-related fixed costs due to electric Customer Choice are recoverable under Michigan legislation as determined by the MPSC. As a result, Detroit Edison recorded an increased regulatory asset relating to stranded costs during the first half of 2003. There are a number of variables and estimates that impact the level of recoverable stranded costs, including weather, sales mix and wholesale prices. As a result, our estimate of stranded costs could increase or decrease in future periods. The regulatory asset will be subject to review by the MPSC in future regulatory proceedings, and we cannot predict the outcome of this matter. See Note 4 — Regulatory Matters.

The June 2000 Michigan legislation imposed a rate freeze for all classes of customers through 2003. In addition, the MPSC determined that adjusting rates for changes in fuel and purchased power through continuance of the Power Supply Cost Recovery (PSCR) clause would be inconsistent with the rate freeze, therefore the MPSC suspended the PSCR clause. It is unclear at this time whether the PSCR clause will remain suspended beyond 2003. Detroit Edison filed a rate case in June 2003 addressing this and other issues. We cannot predict the outcome of this matter. See Note 4 — Regulatory Matters.

Future operating results are expected to vary as a result of factors such as regulatory proceedings, weather, changes in economic conditions and the level of customer participation in the electric Customer Choice program.

Energy Services

Energy Services is comprised of Coal-Based Fuels, On-Site Energy Projects and Merchant Generation. Coal-Based Fuels operations include producing synthetic fuel from nine synfuel plants and producing coke from three coke battery plants. Both processes generate tax credits under Section 29 of the Internal Revenue Code. Synfuel-related Section 29 tax credits expire in 2007. Section 29 tax credits for two of our three coke batteries expired at the end of 2002 with the third expiring in 2007. On-Site Energy Projects include pulverized coal injection, generation, steam production, chilled water production, wastewater treatment and compressed air. Merchant Generation owns and operates four gas-fired peaking electric generating plants and develops and acquires gas and coal-fired generation.

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    Three Months Ended     Six Months Ended  
    June 30     June 30  
   
   
 
(in Millions)   2003     2002     2003     2002  
   
   
   
   
 
Operating Revenues
  $ 300     $ 126     $ 530     $ 254  
Fuel and Purchased Power
    195       56       368       117  
Operation and Maintenance
    97       73       194       151  
Depreciation and Amortization
    3       9       7       17  
Taxes other than Income
    5       3       9       5  
 
 
   
   
   
 
Operating Loss
          (15 )     (48 )     (36 )
Other (Income) and Deductions
    10       12       17       25  
Income Tax Benefit
    86       57       192       123  
 
 
   
   
   
 
Net Income
  $ 76     $ 30     $ 127     $ 62  
 
 
   
   
   
 

Energy Services earnings increased $46 million for the 2003 second quarter and $65 million in the 2003 six-month period reflecting higher synfuel production and a $19 million net of tax gain from the settlement of a tolling agreement at one of our generation facilities. This synfuel production increase and tolling gain were partially offset by a $10 million net of tax reserve established for receivables associated with a large customer that filed for bankruptcy. During 2002, four synfuel facilities became fully operational and interests in two facilities were sold. These two events resulted in significantly higher operating revenues and expenses in the first half of 2003 relative to the same period in 2002. Synfuel projects generate operating losses, which are more than offset by the resulting tax credits. The income tax benefit includes tax credits actually earned based on synfuel production and sales. The level of tax credits has been adjusted at the Corporate & Other segment in order that the DTE Energy consolidated income tax expense during the quarter reflects the estimated calendar year effective rate. See Notes 5 and 8.

Outlook - Energy Services’ strategy is to continue leveraging our extensive energy-related operating experience and project management capability to develop and grow the on-site energy and merchant generating businesses. A significant portion of Energy Services’ earnings consist of synfuel-related Section 29 tax credits. The level of tax credits generated in future periods will be affected by fluctuations in estimated annual taxable earnings and our ability to sell interests in synfuel projects. We continue to evaluate opportunities to sell interests in some or all of our synfuel plants. However, the timing and number of our synfuel sales will depend in part on the resolution of the Internal Revenue Service’s (IRS’s) review of issues concerning chemical change as discussed more fully in the “Synthetic Fuel Operations” section that follows.

Energy Marketing & Trading

Energy Marketing & Trading consists of the electric and gas marketing and trading operations of DTE Energy. Energy Marketing & Trading focuses on physical power marketing and structured transactions, as well as the enhancement of returns from DTE Energy’s power plants, natural gas pipelines and storage assets. To this end, Energy Marketing & Trading enters into forwards, futures, swaps and option contracts as part of its trading strategy.

Energy Marketing & Trading’s loss increased $10 million in the 2003 second quarter from the comparable 2002 period due to unfavorable mark-to-market earnings associated with gas storage activities, partially offset by increased realized margins on the delivery of power and natural gas.

Our year to date earnings increased $16 million and were impacted by the effect of changing our accounting for gas inventory. Through December 2002, our physical gas in storage was marked to the current spot price under fair value accounting rules. To comply with new accounting requirements

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resulting from the rescission of Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” we changed to the average cost method for our gas inventories, effective January 2003. As a result of discontinuing the application of the fair value method to our gas inventories and the effect of the rescission of EITF 98-10 on our energy contracts, we recorded a cumulative effect of accounting change that reduced earnings in January 2003 (Note 2). The effect of the accounting change was offset as a significant portion of the revalued gas inventory was sold in the 2003 first quarter, thereby increasing gross margins.

Outlook — Energy Marketing & Trading will seek to gradually expand its business in a manner consistent with and complementary to the growth of our other business segments. Gas storage and transportation capacity enhances our ability to provide reliable and custom-tailored bundled services to large-volume end users and utilities. This capacity, coupled with the synergies from DTE Energy’s other businesses, positions the segment to capitalize on opportunities for expansion of its market base.

Significant portions of the Energy Marketing & Trading portfolio, although economically hedged, include a combination of derivative financial instruments as well as inventory, owned assets and certain capacity contracts that are not considered derivatives. As a result, Energy Marketing & Trading will experience earnings volatility as derivatives are marked to market without revaluing the underlying non-derivative contracts and assets.

ENERGY DISTRIBUTION

Power Distribution

Power Distribution is comprised of the electric distribution services of Detroit Edison. Power Distribution distributes electricity generated by Energy Resources and alternative electric suppliers to Detroit Edison’s 2.1 million customers.

Power Distribution earnings decreased $34 million during the 2003 second quarter and $66 million in the 2003 six-month period. Results were affected by a catastrophic ice storm that resulted in over 400,000 customers losing power. Restoration costs associated with the ice storm reduced after tax earnings by approximately $25 million, net of insurance. Both periods were also impacted by higher operation and maintenance expenses and reduced electric deliveries and operating revenues due to milder weather. The increased operation and maintenance expenses are attributable to higher employee pension and healthcare benefit costs and increased costs associated with customer service process improvements. Results for the 2003 six-month period also reflect a net of tax loss of $14 million on the sale of our unprofitable steam heating business (Note 3).

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    Three Months Ended     Six Months Ended  
    June 30     June 30  
   
   
 
(in Millions)   2003     2002     2003     2002  
   
   
   
   
 
Operating Revenues
  $ 281     $ 302     $ 601     $ 615  
Fuel and Purchased Power
    2       3       9       12  
Operation and Maintenance
    186       146       368       285  
Depreciation and Amortization
    62       62       125       124  
Taxes other than Income
    27       29       56       60  
 
 
   
   
   
 
Operating Income
    4       62       43       134  
Other (Income) and Deductions
    29       35       73       66  
Income Tax Benefit (Provision)
    9       (9 )     10       (22 )
 
 
   
   
   
 
Net Income (Loss)
  $ (16 )   $ 18     $ (20 )   $ 46  
 
 
   
   
   
 
Operating Income as a Percent of Operating Revenues
    1 %     21 %     7 %     22 %
                                 
    Three Months Ended     Six Months Ended  
Electric Deliveries   June 30     June 30  
 
   
 
(in Thousands of MWh)   2003     2002     2003     2002  
   
   
   
   
 
Residential
    3,243       3,527       7,098       7,247  
Commercial
    3,962       4,718       8,088       9,060  
Industrial
    3,134       3,537       6,219       6,869  
Wholesale
    550       550       1,126       1,092  
Other
    89       85       196       197  
 
 
   
   
   
 
 
    10,978       12,417       22,727       24,465  
Electric Choice
    1,844       761       3,051       1,642  
 
 
   
   
   
 
Total Electric Sales and Deliveries
    12,822       13,178       25,778       26,107  
 
 
   
   
   
 

Outlook — Regulated electric system deliveries are expected to increase in the remainder of 2003 due to continued territory and economic growth. Operating results are expected to vary as a result of external factors such as weather, changes in economic conditions and the severity and frequency of storms. As previously mentioned, Detroit Edison filed a rate case in June 2003 to address future operating costs and other issues.

In July 2003, a catastrophic windstorm in our service territory resulted in over 190,000 customers losing power. We incurred restoration costs totaling approximately $20 million, and a substantial portion of such costs are covered by storm insurance.

Non-regulated

Non-regulated Energy Distribution operations consist primarily of DTE Energy Technologies that markets and distributes a portfolio of distributed generation products, provides application engineering, and monitors and manages generation system operations.

Non-regulated losses increased $1 million in the 2003 second quarter and $2 million in the 2003 six-month period from the comparable 2002 periods.

Outlook — DTE Energy Technologies expects to continue the expansion of its product portfolios and support capabilities in North America and the development of marketing relationships in other parts of the

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world. We plan to develop and launch new products in 2003 that are critical to our plan to increase revenues and generate operating profits by 2004.

ENERGY GAS

Gas Distribution

Gas Distribution operations include gas distribution services primarily provided by MichCon, our gas utility that purchases, stores and distributes natural gas to 1.2 million residential, commercial and industrial customers located throughout Michigan.

Gas Distribution’s loss increased $7 million during the 2003 second quarter and net income declined $2 million for the 2003 six-month period. Earnings reflect higher operation and maintenance expenses and a $26.5 million reserve recorded in the first quarter of 2003 for the potential disallowance in gas costs pursuant to a March 2003 MPSC order in MichCon’s 2002 GCR plan case (Note 4). The increase in operation and maintenance expenses were due to higher employee pension and healthcare benefit costs and increased costs associated with customer service process improvements. Partially offsetting the decline was higher operating revenues due to colder than normal weather. Also impacting the comparison was increased gas costs which were offset by higher revenues under the gas cost recovery mechanism. The income tax provision was favorably affected by an increase in the amortization of tax benefits previously deferred in accordance with MPSC regulations.

                                 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
   
   
 
(in Millions)   2003     2002     2003     2002  
 
   
   
   
 
Operating Revenues
  $ 289     $ 240     $ 928     $ 841  
Cost of Gas
    163       115       593       506  
 
 
   
   
   
 
Gross Margin
    126       125       335       335  
Operation and Maintenance
    86       80       167       152  
Depreciation and Amortization
    26       26       50       51  
Taxes other than Income
    14       11       31       28  
 
 
   
   
   
 
Operating Income
          8       87       104  
Other (Income) and Deductions
    11       9       22       21  
Income Tax Benefit (Provision)
    3             (14 )     (30 )
 
 
   
   
   
 
Net Income (Loss)
  $ (8 )   $ (1 )   $ 51     $ 53  
 
 
   
   
   
 
Operating Income as a Percent of Operating Revenues
    %     3 %     9 %     12 %

Outlook — We expect gas restructuring to continue resulting in increased customer choice in the gas sales business. In December 2001, the MPSC issued an order that continues the gas Customer Choice program on a permanent and expanding basis beginning with the conclusion of the three-year temporary program in March 2002. Beginning in April 2003, up to approximately 60% of customers can participate and beginning April 2004, all 1.2 million of MichCon’s gas customers could choose to participate. Since MichCon continues to transport and deliver the gas to the participating customer premises at prices comparable to margins earned on gas sales, customers switching to other suppliers have little impact on MichCon’s earnings. As of June 2003, approximately 132,000 customers were participating in the gas Customer Choice program.

As a result of the continued increase in operating costs, MichCon expects to file a rate case in the latter half of 2003.

Future operating results are expected to vary as a result of factors such as regulatory proceedings, weather and changes in economic conditions.

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Non-regulated

Non-regulated operations include the gas and oil production business, and the gas Pipelines & Processing business. Our production business produces gas from proven reserves owned in northern Michigan and sells the gas to the Energy Marketing & Trading segment. Pipelines & Processing has partnership interests in two interstate transmission pipelines, seven carbon dioxide processing facilities and a natural gas storage field, as well as contract rights to another natural gas storage field. The assets of these businesses are primarily supported by the Energy Marketing & Trading segment.

Non-regulated earnings decreased $2 million during the 2003 second quarter from the comparable 2002 period and were unchanged for the 2003 six-month period.

Outlook — We expect to further develop our gas production properties in northern Michigan and our pipelines, processing and storage assets to support other DTE Energy businesses. Additionally, we expect to continue exploring opportunities in the coal bed methane gas production business to leverage our production, coal and low cost operating capabilities.

CORPORATE & OTHER

Corporate & Other losses increased $82 million for the 2003 second quarter and $149 million in the 2003 six-month period due to unfavorable effective income tax rate adjustments. Corporate & Other records necessary adjustments in order that the consolidated income tax expense during the quarter reflects the estimated calendar year effective rate. The higher adjustments were necessary because our estimated annual pre-tax income and ability to utilize synfuel-related Section 29 tax credits generated differed from our first quarter estimates. Due to the suspension of the issuance of private letter rulings (PLRs) by the IRS, we have reduced planned synthetic fuel production for the second half of the year. The suspension and reduced production have resulted in a higher anticipated effective tax rate for the year. The quarterly effective tax rate adjustment does not impact total year earnings (Notes 5 and 8). The 2003 six-month period was also affected by a $15 million cash contribution to the DTE Energy Foundation which was funded with proceeds received from the sale of ITC (Note 3).

CAPITAL RESOURCES AND LIQUIDITY

                     
        Six Months Ended  
        June 30  
       
 
(in Millions)   2003     2002  
 
   
 
Cash and Cash Equivalents
               
Cash Flow From (Used For)
               
 
Operating activities:
               
   
Net income, depreciation, depletion, amortization and deferred taxes
  $ 558     $ 630  
   
Pension contribution
    (222 )      
   
Working capital and other
    (37 )     (258 )
 
 
   
 
 
    299       372  
 
Investing activities
    304       (531 )
 
Financing activities
    (633 )     (27 )
 
 
   
 
Net Decrease in Cash and Cash Equivalents
  $ (30 )   $ (186 )
 
 
   
 

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Operating Activities

Net cash from operating activities decreased $73 million during the first six months of 2003 as compared to the same 2002 period. The decrease reflects a decline of $72 million in net income, after adjusting for non-cash items (depreciation, depletion, amortization, and deferred taxes), partially offset by decreased working capital, pension and other requirements of $1 million. These requirements reflect an increase in accounts payable and a reduction in fuel and gas inventories, offset by higher accounts receivable balances and a $222 million cash contribution to our pension plan in 2003.

Investing Activities

Net cash relating to investing activities improved $835 million in the first six-months of 2003 as compared to the same 2002 period primarily due to the sale of ITC, lower contractually designated funds for debt service and decreased non-regulated plant expenditures.

Financing Activities

Net cash used for financing activities increased $606 million during the first six-months of 2003 as compared to the same 2002 period due to higher redemptions of long-term debt and lower proceeds from the issuances of common stock.

In February 2003, MichCon issued $200 million of 5.7% senior notes due in March 2033. The proceeds were used for debt redemption and general corporate purposes.

In April 2003, DTE Energy issued $400 million of 6-3/8% senior notes due in April 2033. In conjunction with this issuance, DTE Energy exchanged $100 million principal amount of existing DTE Enterprises Inc. debt due April 2008. The proceeds were used for debt redemptions and general corporate purposes.

In June 2003, DTE Energy redeemed $100 million principal amount of 6.17% Remarketed Notes due in 2038.

SYNTHETIC FUEL OPERATIONS

We operate nine synthetic fuel production facilities, seven of which are wholly owned. Synfuel facilities chemically change coal, including waste and marginal coal, into a synthetic fuel as determined under applicable IRS rules. Section 29 of the Internal Revenue Code provides tax credits for the production and sale of solid synthetic fuels produced from coal. To qualify for the Section 29 tax credits, the synthetic fuel must meet three primary conditions: (1) there must be a significant chemical change in the coal feedstock, (2) the product must be sold to an unaffiliated entity, and (3) the production facility must have been placed in service before July 1, 1998. In addition to meeting the qualifying conditions, a taxpayer must have sufficient taxable income to earn the Section 29 credits. The IRS has suspended the issuance of PLRs relating to synthetic fuel projects pending their review of issues concerning chemical change which is the basis for earning Section 29 tax credits. See Note 8 for a further discussion of synthetic fuel matters.

ELECTRIC CUSTOMER CHOICE PROGRAM

The electric Customer Choice program as originally structured in Michigan anticipated an eventual transition to a totally competitive environment where customers would be charged market-based rates for their electricity. Various developments in the energy industry have caused the deregulation of electric generation to proceed at a much slower rate. As a result, Detroit Edison’s rates continue to be regulated by the MPSC. This continued regulation has hindered Detroit Edison’s ability to retain customers that are

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choosing alternative suppliers under the electric Customer Choice program. Detroit Edison’s results have been unfavorably impacted by the lack of full recovery of lost margins and other costs associated with the electric Customer Choice program. Although the MPSC has encouraged a collaborative process to address issues relating to customer choice, they continue to delay finalizing a mechanism to provide for the recovery of stranded costs. Detroit Edison has been an active participant in this collaborative process. However, efforts to date have not been effective in resolving the issue of the recovery of stranded costs. Detroit Edison has addressed this issue in its June 2003 rate filing and is also considering a legislative solution to this problem later this year. The continued delay in the timely and full recovery of stranded costs unfavorably impacts operating results.

ENVIRONMENTAL MATTERS

EPA ozone transport regulations and final new air quality standards relating to ozone and particulate air pollution will continue to impact us. Detroit Edison spent approximately $500 million through June 2003 and estimates that it will incur approximately $300 to $400 million of future capital expenditures over the next five to eight years to comply with the existing air quality standards. Recovery of these costs is included in our June 2003 electric rate case. In addition, we maintain the option to securitize these costs after the completion of this rate case.

The Environmental Protection Agency (EPA) initiated enforcement actions against several major electric utilities citing violations of new source provisions of the Clean Air Act. Detroit Edison received and responded to information requests from the EPA on this subject. The EPA has not initiated proceedings against Detroit Edison. The United States District Court for the Southern District of Ohio Eastern Division issued a decision on August 7, 2003 finding Ohio Edison in violation of the new source provisions of the Clean Air Act. If the Court’s decision is upheld, the electric utility industry could be required to invest substantial amounts in pollution control equipment. We cannot predict the future impact of this issue upon Detroit Edison.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 2 — New Accounting Pronouncements for discussion of new accounting pronouncements.

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FAIR VALUE OF CONTRACTS

The following disclosures are voluntary and have been developed through efforts of the Committee of Chief Risk Officers, a working group of chief risk officers from companies active in both physical and financial energy trading and marketing. We believe the disclosures provide enhanced transparency of the activities and position of our Energy Trading & Marketing segment.

Roll-Forward of Mark-to-Market Energy Contract Net Assets

The following tables provide details on changes in our mark-to-market (MTM) net asset or (liability) position during 2003.

                                   
      Proprietary     Structured     Owned          
(in Millions)   Trading (1)     Contracts (2)     Assets (3)     Total  
 
   
   
   
 
Energy Marketing & Trading Segment
                               
 
MTM at December 31, 2002
  $ 15     $ 19     $ (50 )   $ (16 )
 
Cumulative effect adjustment (4)
    (2 )     (1 )     17       14  
 
Reclassification to realized at settlement of contract
    (6 )     (7 )     19       6  
 
Net change in option premiums
    (10 )                 (10 )
 
Other changes in fair value
    12       4       (22 )     (6 )
 
 
   
   
   
 
 
MTM at June 30, 2003
  $ 9     $ 15     $ (36 )     (12 )
 
 
   
   
         
Other DTE Energy segments and non-trading activities of the Energy Marketing & Trading segment
                            (141 )
 
                         
 
 
                          $ (153 )
 
                         
 


(1)   “Proprietary Trading” represents derivative activity transacted with the intent of capturing profits on forward price movements.
 
(2)   “Structured Contracts” represent derivative activity transacted with the intent to capture profits by originating substantially offsetting positions with wholesale energy marketers, utilities, retail aggregators and end-users. Although transactions are generally executed with a buyer and seller simultaneously, some positions remain open until a suitable offsetting trade can be executed.
 
(3)   “Owned Assets” represent derivative activity associated with assets owned by DTE Energy, including forward sales of gas production and trades associated with owned transportation and storage capacity. Derivatives are generally executed with the intent of locking in and optimizing profits without creating additional risk.
 
(4)   Excludes the cumulative effect adjustment associated with the change in accounting for gas inventory (Note 2).
                                         
    Proprietary     Structured     Owned                  
(in Millions)   Trading     Contracts     Assets     Eliminations     Total  

 
   
   
   
   
 
Current assets
  $ 127     $ 72     $ 158     $ (9 )   $ 348  
Noncurrent assets
    48       27       185       (15 )     245  
 
 
   
   
   
   
 
Total MTM assets
    175       99       343       (24 )     593  
 
 
   
   
   
   
 
Current liabilities
    (115 )     (62 )     (166 )     9       (334 )
Noncurrent liabilities
    (51 )     (22 )     (213 )     15       (271 )
 
 
   
   
   
   
 
Total MTM liabilities
    (166 )     (84 )     (379 )     24       (605 )
 
 
   
   
   
   
 
Total MTM net assets (liabilities)
  $ 9     $ 15     $ (36 )   $     $ (12 )
 
 
   
   
   
   
 

Maturity of Fair Value of MTM Energy Contract Net Assets

Effective January 1, 2003, we fully reserve all unrealized gains and losses related to periods beyond the liquid trading time frame. Our intent is to recognize MTM activity only when pricing data is obtained from active quotes and published indexes.

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The table below shows the maturity of the MTM positions of our energy contracts.

                                         
                                    Total  
                            2006 &     Fair  
(in Millions)   2003     2004     2005     Beyond     Value  

 
   
   
   
   
 
Proprietary Trading
  $ 14     $ (2 )   $ (3 )   $     $ 9  
Structured Contracts
    5       8       2             15  
Owned Assets
    (14 )     (12 )     5       (15 )     (36 )
 
 
   
   
   
   
 
Total
  $ 5     $ (6 )   $ 4     $ (15 )   $ (12 )
 
 
   
   
   
   
 

Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

DTE Energy 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. We also are exposed to the risk of market price fluctuations on gas sales and purchase contracts, gas production and gas inventories. To limit our exposure to commodity price fluctuations, we have entered into a series of electricity and gas futures, forwards, option and swap contracts.

Interest Rate Risk

DTE Energy is subject to interest rate risk in connection with the issuance of debt and preferred securities. In order to manage interest costs, we use treasury locks and interest rate swap agreements. 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). There was no material change in interest rate risk during the first six-months of 2003.

Summary of Sensitivity Analysis

We performed a sensitivity analysis calculating the impact of changes in fair values utilizing applicable forward commodity rates if they occurred at June 30, 2003:

                         
(in Millions)                        
Activity   Increase of 10%     Decrease of 10%     Change in the fair value of

 
   
   
Gas Contracts
  $ (24 )   $ 23     Commodity contracts
Power Contracts
  $ (1 )   $ 2     Commodity contracts
Interest Rate Risk
  $ (294 )   $ 319     Long-term debt

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CONTROLS AND PROCEDURES

(a)  Evaluation of disclosure controls and procedures

  The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in the Exchange Act Rules 13a — 15(e) and 15d — 15(e)) as of the end of the period covered by this report, and have concluded that, such controls and procedures were effective at ensuring that required information will be disclosed on a timely basis in reports filed under the Exchange Act.

(b)  Changes in internal controls

  There have been no significant changes (including corrective actions with regard to significant deficiencies or material weaknesses) in the Company’s internal controls or in other factors that could significantly affect these controls.

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DTE ENERGY COMPANY
CONSOLIDATED STATEMENT OF OPERATIONS (UNAUDITED)

                                       
          Three Months Ended     Six Months Ended  
          June 30     June 30  
         
   
 
(in Millions, Except per Share Amounts)   2003     2002     2003     2002  
 
   
   
   
 
Operating Revenues
  $ 1,600     $ 1,474     $ 3,695     $ 3,368  
 
 
   
   
   
 
Operating Expenses
                               
   
Fuel, purchased power and gas
    493       403       1,306       1,138  
   
Operation and maintenance
    733       623       1,488       1,166  
   
Depreciation, depletion and amortization
    180       180       377       369  
   
Taxes other than income
    87       81       184       174  
 
 
   
   
   
 
 
    1,493       1,287       3,355       2,847  
 
 
   
   
   
 
Operating Income
    107       187       340       521  
 
 
   
   
   
 
Other (Income) and Deductions
                               
   
Interest expense
    132       136       265       272  
   
Preferred stock dividends of subsidiaries
    6       5       12       13  
   
Interest income
    (7 )     (6 )     (15 )     (11 )
   
Other income
    (18 )     (28 )     (31 )     (37 )
   
Other expenses
    18       27       51       42  
 
 
   
   
   
 
 
    131       134       282       279  
 
 
   
   
   
 
Income (Loss) Before Income Taxes
    (24 )     53       58       242  
Income Tax Expense (Benefit)
    13       (8 )     (13 )     (11 )
 
 
   
   
   
 
Income (Loss) from Continuing Operations
    (37 )     61       71       253  
 
 
   
   
   
 
Discontinued Operations — ITC (Note 3):
                               
 
Income from operations
          7       5       15  
 
Gain on sale
    (2 )           67        
 
 
   
   
   
 
 
    (2 )     7       72       15  
 
 
   
   
   
 
Cumulative Effect of Accounting Changes (Note 2):
                               
 
Asset retirement obligations
                (11 )      
 
Energy trading activities
                (16 )      
 
 
   
   
   
 
 
                (27 )      
 
 
   
   
   
 
Net Income (Loss)
  $ (39 )   $ 68     $ 116     $ 268  
 
 
   
   
   
 
Basic Earnings (Loss) per Common Share
                               
   
Income (Loss) from continuing operations
  $ (.22 )   $ .38     $ .43     $ 1.57  
   
Discontinued operations
    (.01 )     .04       .43       .09  
   
Cumulative effect of accounting changes
                (.17 )      
 
 
   
   
   
 
     
Total
  $ (.23 )   $ .42     $ .69     $ 1.66  
 
 
   
   
   
 
Diluted Earnings (Loss) per Common Share
                               
   
Income (Loss) from continuing operations
  $ (.22 )   $ .38     $ .42     $ 1.57  
   
Discontinued operations
    (.01 )     .04       .43       .09  
   
Cumulative effect of accounting changes
                (.16 )      
 
 
   
   
   
 
     
Total
  $ (.23 )   $ .42     $ .69     $ 1.66  
 
 
   
   
   
 
Average Common Shares
                               
   
Basic
    168       161       167       161  
   
Diluted
    168       162       168       162  
Dividends Declared per Common Share
  $ .515     $ .515     $ 1.03     $ 1.03  

See Notes to Consolidated Financial Statements (Unaudited)

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DTE ENERGY COMPANY
CONSOLIDATED STATEMENT OF FINANCIAL POSITION

                     
        (Unaudited)          
        June 30     December 31  
(in Millions)   2003     2002  
 
   
 
ASSETS
               
Current Assets
               
 
Cash and cash equivalents
  $ 103     $ 133  
 
Restricted cash
    126       237  
 
Accounts receivable
               
   
Customer (less allowance for doubtful accounts of $123 and $82, respectively)
    930       902  
   
Accrued unbilled revenues
    190       296  
   
Other
    370       237  
 
Inventories
               
   
Fuel and gas
    367       413  
   
Materials and supplies
    159       163  
 
Assets from risk management and trading activities
    349       224  
 
Other
    114       159  
 
 
 
   
 
 
    2,708       2,764  
 
 
   
 
Investments
               
 
Nuclear decommissioning trust funds
    466       417  
 
Other
    484       487  
 
 
 
   
 
 
    950       904  
 
 
   
 
Property
               
 
Property, plant and equipment
    17,534       17,862  
 
Less accumulated depreciation and depletion
    (7,856 )     (8,049 )
 
 
 
   
 
 
    9,678       9,813  
 
 
   
 
Other Assets
               
 
Goodwill
    2,086       2,119  
 
Regulatory assets (Notes 2 and 4)
    2,066       1,197  
 
Securitized regulatory assets
    1,571       1,613  
 
Assets from risk management and trading activities
    247       152  
 
Prepaid pension assets
    177       172  
 
Other
    539       504  
 
 
   
 
 
    6,686       5,757  
 
 
   
 
Total Assets
  $ 20,022     $ 19,238  
 
 
   
 

See Notes to Consolidated Financial Statements (Unaudited)

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DTE ENERGY COMPANY
CONSOLIDATED STATEMENT OF FINANCIAL POSITION

                   
      (Unaudited)          
      June 30     December 31  
(in Millions, Except Shares)   2003     2002  
 
   
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
               
Current Liabilities
               
 
Accounts payable
  $ 852     $ 647  
 
Accrued interest
    114       115  
 
Dividends payable
    91       90  
 
Accrued payroll
    41       49  
 
Short-term borrowings
    231       414  
 
Current portion of long-term debt, including capital leases
    744       1,018  
 
Liabilities from risk management and trading activities
    404       284  
 
Other
    553       596  
 
 
 
   
 
 
    3,030       3,213  
 
 
   
 
Other Liabilities
               
 
Deferred income taxes
    1,154       916  
 
Regulatory liabilities
    171       179  
 
Asset retirement obligations (Note 2)
    841        
 
Unamortized investment tax credit
    162       168  
 
Liabilities from risk management and trading activities
    345       208  
 
Liabilities from transportation and storage contracts
    497       523  
 
Accrued pension liability
    389       582  
 
Nuclear decommissioning (Note 2)
    59       416  
 
Other
    691       683  
 
 
 
   
 
 
    4,309       3,675  
 
 
   
 
Long-Term Debt
               
 
Mortgage bonds, notes and other
    5,671       5,656  
 
Securitization bonds
    1,539       1,585  
 
Equity-linked securities
    188       191  
 
Capital lease obligations
    79       82  
 
 
 
   
 
 
    7,477       7,514  
 
 
   
 
Contingencies (Notes 4 and 8)
               
 
Obligated Mandatorily Redeemable Preferred Securities of Subsidiaries Holding Solely Debentures of DTE Energy or Enterprises
    271       271  
 
 
   
 
Shareholders’ Equity
               
 
Common stock, without par value, 400,000,000 shares authorized, 168,012,997 and 167,462,430 shares issued and outstanding, respectively
    3,076       3,052  
 
Retained earnings
    2,080       2,132  
 
Accumulated other comprehensive loss
    (221 )     (619 )
 
 
 
   
 
 
    4,935       4,565  
 
 
   
 
Total Liabilities and Shareholders’ Equity
  $ 20,022     $ 19,238  
 
 
   
 

See Notes to Consolidated Financial Statements (Unaudited)

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DTE ENERGY COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED)

                       
          Six Months Ended  
          June 30  
         
 
(in Millions)   2003     2002  
 
   
 
Operating Activities
               
   
Net Income
  $ 116     $ 268  
   
Adjustments to reconcile net income to net cash from operating activities:
               
     
Depreciation, depletion and amortization
    381       380  
     
Deferred income taxes
    61       (18 )
     
Gain on sale of assets, net
    (136 )      
     
Cumulative effect of accounting changes
    27        
     
Changes in assets and liabilities, exclusive of changes shown separately (Note 1)
    (150 )     (258 )
 
 
   
 
     
Net cash from operating activities
    299       372  
 
 
   
 
Investing Activities
               
   
Plant and equipment expenditures — regulated
    (356 )     (345 )
   
Plant and equipment expenditures — non-regulated
    (44 )     (110 )
   
Proceeds from sales of assets
    647       9  
   
Restricted cash for debt redemptions
    110       5  
   
Other investments
    (53 )     (90 )
 
 
   
 
     
Net cash from (used for) investing activities
    304       (531 )
 
 
   
 
Financing Activities
               
   
Issuance of long-term debt
    480       389  
   
Redemption of long-term debt
    (800 )     (339 )
   
Issuance of preferred securities
          180  
   
Redemption of preferred securities
          (180 )
   
Short-term borrowings, net
    (184 )     (166 )
   
Issuance of common stock
    21       265  
   
Dividends on common stock
    (173 )     (166 )
   
Other
    23       (10 )
 
 
   
 
     
Net cash used for financing activities
    (633 )     (27 )
 
 
   
 
Net Increase (Decrease) in Cash and Cash Equivalents
    (30 )     (186 )
Cash and Cash Equivalents at Beginning of the Period
    133       268  
 
 
   
 
Cash and Cash Equivalents at End of the Period
  $ 103     $ 82  
 
 
   
 

See Notes to Consolidated Financial Statements (Unaudited)

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DTE ENERGY COMPANY
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
AND COMPREHENSIVE INCOME (UNAUDITED)

                                           
                              Accumulated          
      Common Stock             Other          
     
    Retained     Comprehensive          
      Shares     Amount     Earnings     Loss     Total  
     
   
   
   
   
 
(Dollars in Millions, Shares in Thousands)
                                       
Balance, January 1, 2003
    167,462     $ 3,052     $ 2,132     $ (619 )   $ 4,565  
 
 
   
   
   
   
 
 
Net income
                116             116  
 
Issuance of new shares
    602       25                   25  
 
Dividends declared on common stock
                  (174 )           (174 )
 
Repurchase and retirement of common stock
    (51 )     (1 )     (1 )           (2 )
 
Pension obligations (Note 4)
                      417       417  
 
Net change in unrealized losses on derivatives, net of tax
                      (19 )     (19 )
 
Other
                7             7  
 
 
   
   
   
   
 
Balance, June 30, 2003
    168,013     $ 3,076     $ 2,080     $ (221 )   $ 4,935  
 
 
   
   
   
   
 

The following table displays other comprehensive income (loss) for the six-month periods ended June 30:

                     
(in Millions)   2003     2002  
 
   
 
Net income
  $ 116     $ 268  
 
 
   
 
Other comprehensive income (loss), net of tax:
               
 
Net unrealized income (losses) on derivatives:
               
 
Gains (losses) arising during the period, net of taxes of $(9) and $(27), respectively
    (17 )     (51 )
 
Amounts reclassified to earnings, net of taxes of $(1) and $4, respectively
    (2 )     8  
 
 
   
 
 
    (19 )     (43 )
 
Pension obligations, net of taxes of $224 (Note 4)
    417        
 
 
   
 
 
    398       (43 )
 
 
   
 
Comprehensive income
  $ 514     $ 225  
 
 
   
 

See Notes to Consolidated Financial Statements (Unaudited)

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DTE Energy Company
Notes to Consolidated Financial Statements (unaudited)

NOTE 1 — GENERAL

These consolidated financial statements should be read in conjunction with the notes to consolidated financial statements included in the 2002 Annual Report on Form 10-K and the July 14, 2003 Current Report on Form 8-K.

The accompanying consolidated financial statements are prepared using accounting principles generally accepted in the United States of America. These accounting principles require us to use estimates and assumptions that impact the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results may differ from our estimates.

The consolidated financial statements are unaudited, but in our opinion include all adjustments necessary for a fair statement of the results for the interim periods. Financial results for this interim period are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year.

We reclassified some prior year balances to match the current year’s presentation.

Stock-Based Compensation

We have a stock-based employee compensation plan. The plan permits the awarding of various stock awards, including options, restricted stock and performance shares. We account for stock awards under the plan using the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees.” No compensation cost related to stock options is reflected in net income, as all options granted had an exercise price equal to the market value of the underlying common stock on the date of grant. The recognition provisions under SFAS No. 123,“Accounting for Stock-Based Compensation,” require the recording of compensation expense for stock options equal to their fair value at date of grant as determined using an option pricing model. The following table illustrates the effect on net income and earnings per share if we had recorded compensation expense for options granted under the fair value recognition provisions of SFAS No. 123.

                                   
      Three Months Ended     Six Months Ended  
      June 30     June 30  
     
   
 
(in Millions, except per share amounts)   2003     2002     2003     2002  

 
   
   
   
 
Net Income (Loss) As Reported
  $ (39 )   $ 68     $ 116     $ 268  
Less: Total stock-based expense (1)
    (1 )     (2 )     (3 )     (4 )
 
 
   
   
   
 
Pro Forma Net Income (Loss)
  $ (40 )   $ 66     $ 113     $ 264  
 
 
   
   
   
 
Income (Loss) Per Share
             
 
Basic — as reported
  $ (.23 )   $ .42     $ .69     $ 1.66  
 
 
   
   
   
 
 
Basic — pro forma
  $ (.24 )   $ .41     $ .67     $ 1.64  
 
 
   
   
   
 
 
Diluted — as reported
  $ (.23 )   $ .42     $ .69     $ 1.66  
 
 
   
   
   
 
 
Diluted — pro forma
  $ (.24 )   $ .41     $ .67     $ 1.63  
 
 
   
   
   
 


(1)   Expense determined using a Black-Scholes based option pricing model.

Issuance of Stock by Equity Investees

In 1997, DTE Energy and Mechanical Technology Incorporated formed Plug Power Inc. to design and develop on-site electric fuel cell power generation systems. Since Plug Power is considered a development stage company, generally accepted accounting principles require us to record gains and

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losses from Plug Power stock issuances as an adjustment to equity. In March 2003, Plug Power issued approximately 8.95 million shares of common stock in conjunction with its acquisition of H Power Corp.

As a result of Plug Power’s common stock issuance, we recorded an increase of $8 million in our investment and an after-tax increase of $5 million to equity. At June 30, 2003, we owned approximately 23% of Plug Power’s common stock.

Consolidated Statement of Cash Flows

We consider investments purchased with a maturity of three months or less to be cash equivalents. Cash contractually designated for debt service is classified as restricted cash. The components of changes in assets and liabilities follows.

                   
      Six Months Ended  
      June 30  
     
 
(in Millions)   2003     2002  
 
   
 
Changes in Assets and Liabilities, Exclusive of Changes Shown Separately
               
 
Accounts receivable, net
  $ (147 )   $ (118 )
 
Accrued unbilled receivables
    105       32  
 
Accrued gas cost recovery revenue
    (33 )     (38 )
 
Inventories
    43       (30 )
 
Accrued/Prepaid pensions
    (147 )     25  
 
Accounts payable
    206       (8 )
 
Income taxes payable
    (50 )     (40 )
 
General taxes
    (14 )     (31 )
 
Risk management and trading activities
    37       72  
 
Gas inventory equalization
    75       22  
 
Other
    (225 )     (144 )
 
 
   
 
 
  $ (150 )   $ (258 )
 
 
   
 

Other cash and non-cash investing and financing activities for the six-months ended June 30 were as follows:

                   
      Six Months Ended  
      June 30  
     
 
(in Millions)   2003     2002  
 
   
 
Supplementary Cash Flow Information
               
 
Interest paid (excluding interest capitalized)
  $ 267     $ 265  
 
Income taxes paid
  $ 27     $ 55  

NOTE 2 — NEW ACCOUNTING PRONOUNCEMENTS

Asset Retirement Obligations — On January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred. It applies to legal obligations associated with the retirement of long-lived assets resulting from the acquisition, construction, development and (or) the normal operation of a long-lived asset. When a new liability is recorded, an entity will capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its recorded amount or incurs a gain or loss upon settlement.

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We have identified a legal retirement obligation for the decommissioning costs for our Fermi 1 and 2 nuclear plants. To a lesser extent, we have retirement obligations for our synthetic fuel operations, gas production facilities, asphalt plant, gas gathering facilities and various other operations. As to regulated operations, we believe that adoption of SFAS No. 143 results primarily in timing differences in the recognition of legal asset retirement costs that we are currently recovering in rates and will be deferring such differences under SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.”

As a result of adopting SFAS No. 143 on January 1, 2003, we recorded a plant asset of $306 million with offsetting accumulated depreciation of $106 million, a retirement obligation liability of $815 million and reversed previously recognized obligations of $377 million, principally nuclear decommissioning liabilities. We also recorded a cumulative effect amount related to regulated operations as a regulatory asset of $221 million, and a cumulative effect charge against earnings of $11 million for 2003.

The impact of SFAS No. 143 reduced earnings from continuing operations by $1.2 million or $.01 per diluted share and $2.4 million or $.01 per diluted share for the second quarter and six-month period of 2003, respectively. Additionally, had SFAS No. 143 been adopted at January 1, 2002 the pro forma effect on earnings would have been a charge against earnings of $1.2 million or $.01 per diluted share and $2.4 million or $.01 per diluted share for the second quarter and six-month period of 2002, respectively.

A reconciliation of the asset retirement obligation for the 2003 six-month period follows:

         
(in Millions)        
Asset retirement obligations at January 1, 2003
  $ 815  
Accretion
    27  
Liabilities settled
    (1 )
 
 
 
Asset retirement obligations at June 30, 2003
  $ 841  
 
 
 

SFAS No. 143 also requires the quantification of the estimated cost of removal obligations, arising from other than legal obligations, which have been accrued through depreciation charges. At January 1, 2003, we estimate that we had approximately $700 million of previously accrued asset removal costs related to our regulated operations, for other than legal obligations, included in accumulated depreciation.

Energy Trading Activities — Under EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” companies were required to use mark-to-market accounting for contracts utilized in energy trading activities. EITF Issue No. 98-10 was rescinded in October 2002, and energy trading contracts must now be reviewed to determine if they meet the definition of a derivative under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133 requires all derivatives to be recognized in the statement of financial position as either assets or liabilities measured at their fair value and sets forth conditions in which a derivative instrument may be designated as a hedge. SFAS No. 133 also requires that changes in the fair value of derivatives be recognized in earnings unless specific hedge accounting criteria are met. Energy trading contracts not meeting the definition of a derivative are accounted for under settlement accounting, effective October 25, 2002 for new contracts and effective January 1, 2003 for existing contracts.

Additionally, inventory utilized in energy trading activities accounted for under the fair value method of accounting as prescribed by Accounting Research Bulletin (ARB) No. 43 is no longer permitted. DTE Energy’s Energy Marketing & Trading segment uses gas inventory in its trading operations and switched to the average cost inventory accounting method in January 2003.

Effective January 1, 2003, DTE Energy no longer applies EITF Issue No. 98-10 to energy contracts and ARB No. 43 to gas inventory. As a result of discontinuing the application of these accounting principles, we recorded a cumulative effect of accounting change that reduced net income for the first quarter of 2003 by $16 million (net of taxes of $9 million.)

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Consolidation of Variable Interest Entities — FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” requires variable interest entities, previously referred to as special-purpose entities or off-balance sheet structures, to be consolidated by a company if that company is subject to a majority of the risk of loss from the entity’s activities or is entitled to receive a majority of the entity’s returns or both. Effective July 1, 2003, we have adopted the provisions of FASB Interpretation No. 46.

We continue to evaluate our off-balance sheet structures as to whether they fall within the scope of FASB Interpretation No. 46, but the effect of adopting these provisions is not expected to be material.

Derivative Instruments and Hedging Activities — In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” This Statement is effective for contracts entered into or modified after June 30, 2003. We do not believe SFAS No. 149 will have a material impact on our financial statements.

Financial Instruments with Characteristics of Liabilities and Equity — In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” SFAS No. 150 establishes standards for the classification of financial instruments with characteristics of both liabilities and equity as a liability. We have $271 million of obligated mandatorily redeemable preferred securities that are currently classified in the statement of financial position between liabilities and equity that will be reclassified to a liability in the third quarter of 2003.

NOTE 3 — DISPOSITIONS

Disposition of Detroit Edison’s Steam Heating Business

In January 2003, we sold Detroit Edison’s steam heating business to Thermal Ventures II, LLP. This disposition is consistent with DTE Energy’s strategy to divest non-strategic assets. Due to the continuing involvement of Detroit Edison in the steam heating business, including the commitment to purchase $176 million in steam for resale through 2008, fund certain capital improvements and guarantee the buyer’s credit facility, we recorded a net of tax loss of $14 million in the first quarter of 2003. As a result of our continuing involvement, this transaction is not considered a sale for accounting purposes. The steam heating business had assets of $6 million at December 31, 2002, and net losses of $12 million in 2002, net income of $3 million in 2001 and a net loss of $18 million in 2000.

Disposition of International Transmission Company — Discontinued Operation

In December 2002, we entered into a definitive agreement with affiliates of Kohlberg Kravis Roberts & Co. and Trimaran Capital Partners, LLC to sell ITC for $610 million in cash. The sale closed on February 28, 2003 following approval of the transaction by the FERC and resolution of all other contingencies and

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generated a preliminary net of tax gain of $69 million that was subsequently reduced to $67 million in the 2003 second quarter. The sale price is subject to review and further adjustment in the third quarter of 2003 and can be increased or decreased based upon a review of ITC’s closing date balance sheet.

The FERC has encouraged integrated electric utilities to transfer operating control of their transmission facilities to independent operators or sell the facilities to an independent company. DTE Energy’s decision to sell ITC is consistent with our strategic view that maximization of shareholder value and high levels of customer service are best achieved with assets we own, operate and exercise significant control. As provided in FERC regulations, Detroit Edison continues to have fair and open access to Michigan’s electric transmission network. The ITC electric transmission system continues to be operated by the Midwest Independent System Operator, a regional transmission operator. ITC received FERC approval to cap transmission rates charged to Detroit Edison’s customers at current levels until December 31, 2004. Thereafter, rates are subject to adjustment by the FERC.

SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” provides that the results of operations of a component of an entity that has been disposed of should be reported as a discontinued operation when the operations and cash flows of the component have been eliminated from the ongoing operations of the entity and the entity will not have any significant continuing involvement in the operations of the component after the disposal transaction. As a result, we have reported the operations of ITC as a discontinued operation for the periods ended June 30, as shown in the following table:

                                 
    Three Months Ended     Six Months Ended  
(in Millions)   June 30     June 30  
 
   
 
    2003     2002     2003 (3)     2002  
   
   
   
   
 
Revenues (1)
  $     $ 28     $ 21     $ 54  
Expenses (2)
          18       13       31  
 
 
   
   
   
 
Operating income
          10       8       23  
Income tax provision
          3       3       8  
 
 
   
   
   
 
Income from discontinued operations
  $     $ 7     $ 5     $ 15  
 
 
   
   
   
 

(1)  Includes intercompany revenues for the 2002 three-month period of $24 million. For the sixth-month period, intercompany revenues are $18 million for 2003 and $48 million for 2002.

(2)  Excludes general corporate overhead costs that were previously allocated to ITC. Includes $1 million in imputed interest for both periods.

(3)  Represents activity from January 1, 2003 through February 28, 2003 when ITC was sold.

ITC had net fixed assets of approximately $390 million at February 28, 2003 and $388 million at December 31, 2002. For segment reporting purposes, ITC was reported as a component of Energy Distribution — Regulated Power Distribution and Transmission. In conjunction with the sale of ITC, approximately $44 million of goodwill allocated to this segment was written off and reduced the preliminary net of tax gain of $67 million.

NOTE 4 — REGULATORY MATTERS

Transitional Rate Plan

On June 20, 2003, Detroit Edison filed an application for a change in retail electric rates, resumption of the Power Supply Cost Recovery (PSCR) mechanism, and recovery of net stranded costs with the MPSC. Detroit Edison is specifically requesting authority to increase rates on an interim basis by $274 million annually to all customers not subject to a rate cap. Public Act 141 (PA141) became effective in June 2000 and contains provisions freezing rates through 2003 and preventing rate increases for residential customers through 2005 and for small business customers through 2004. Detroit Edison has requested the MPSC act on our interim request in order to be effective January 1, 2004. Concurrent with the order for interim rate relief, Detroit Edison requested reinstatement of

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the PSCR mechanism. The PSCR mechanism allowed Detroit Edison to recover through rates its fuel, fuel-related and purchased power electric expenses and was suspended under PA 141. Detroit Edison is also proposing that base rates for the customer classes still subject to rate caps in 2004 and 2005 be adjusted in an equal and offsetting amount with any change in PSCR adjustments to maintain the total rate level currently in effect. Also, the interim request seeks a five-year surcharge from both full service and electric Customer Choice customers to recover certain deferred regulatory asset balances including electric Customer Choice program implementation costs, return on and of clean air investments made prior to inclusion in rates and net stranded costs for years prior to 2004. This surcharge would be phased in by customer class between 2004 and 2006 as rate caps expire, and would total $109 million annually in 2006.

The application also is requesting a base rate increase for both full service and electric Customer Choice customers totaling $416 million annually (approximately 12% increase) in 2006, after the expiration of all customer rate caps. Detroit Edison is proposing that the $416 million increase be allocated between full service customers ($265 million) and electric Customer Choice customers ($151 million). The final request for rate relief is based on a 50 percent equity-50 percent debt capital structure and a proposed return on equity (ROE) of 11.5%. Detroit Edison is also proposing a ROE sharing mechanism, which will apply to full service and electric Customer Choice customers whose rates are no longer capped under PA 141. The ROE sharing mechanism would be effective for the calendar year in which a final order is received in this case.

Electric Industry Restructuring

Electric Rates, Customer Choice and Stranded Costs - PA 141 provided Detroit Edison with the right to recover net stranded costs, codified and established January 1, 2002 as the date for full implementation of the MPSC’s existing electric Customer Choice program, and required the MPSC to reduce residential electric rates by 5%. At that time, Public Act 142 (PA 142) also became effective. PA 142 provided for the recovery through securitization of “qualified costs” which consist of an electric utility’s regulatory assets, plus various costs, associated with, or resulting from, the establishment of a competitive electric market and the issuance of securitization bonds.

Acting pursuant to PA 141, in an order issued in June 2000, the MPSC reduced Detroit Edison’s residential electric rates by 5% and imposed a rate freeze for all classes of customers through 2003. In April 2001, commercial and industrial rates were lowered by 5% as a result of savings derived from the issuance of securitization bonds in March 2001, as subsequently discussed.

Certain costs may be deferred and recovered once rates can be increased. This rate cap may be lifted when certain market test provisions are met, specifically, when an electric utility has no more than 30% of generation capacity in its relevant market, with consideration for capacity needed to meet a utility’s responsibility to serve its retail customers. Statewide, multi-utility transmission system improvements also are required. In May 2003, Detroit Edison submitted filings with the MPSC regarding the Company’s compliance with the provisions of PA 141 related to market test and transmission system improvements. If the MPSC finds that the Company has complied with the PA 141 provisions, the rate caps established under PA 141 will not continue after the dates specified in the legislation.

As required by PA 141, the MPSC conducted a proceeding to develop a methodology for calculating the net stranded costs associated with electric Customer Choice. In a December 2001 order, the MPSC determined that Detroit Edison could recover net stranded costs associated with the fixed cost component of its electric generation operations. Specifically, there would be an annual filing with the MPSC comparing the receipt of revenues associated with the fixed cost component of its generation services to the revenue requirement for the fixed cost component of those services, inclusive of an allowance for the cost of capital. Any resulting shortfall in recovery, net of mitigation, would be considered a net stranded cost. The MPSC, in its December 2001 order, also determined that Detroit Edison had no net stranded costs in 2000 and consequently established a zero net stranded cost transition charge for billing purposes in 2002. The MPSC authorized

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Detroit Edison to establish a regulatory asset to defer recovery of its incurred stranded costs, subject to review in a subsequent annual net stranded cost proceeding. The MPSC also determined that Detroit Edison should provide a full and offsetting credit for the securitization and tax charges applied to electric Customer Choice bills in 2002. In addition, the MPSC ordered an additional credit on bills equal to the 5% rate reduction realized by full service customers. Both credits were to be funded from savings derived from securitization. The December 2001 order, coupled with lower wholesale power prices in 2002, has encouraged additional customer participation in the electric Customer Choice program and has resulted in the loss of margins attributable to generation services. In May 2002, the MPSC denied Detroit Edison’s request for rehearing and clarification of the December 2001 order. In June 2002, Detroit Edison filed an appeal of the MPSC order at the Michigan Court of Appeals, challenging the legality of specific aspects of the MPSC order. The Court of Appeals has not yet issued a decision on this appeal.

In May 2002, Detroit Edison submitted its 2001 net stranded cost filing with the MPSC. The filing provides refinements to the MPSC Staff’s calculation of net stranded costs that was adopted in the December 2001 order, seeks more timely recovery of net stranded costs, and addresses issues raised by the continuation of securitization offsets and rate reduction equalization credits. Detroit Edison’s filing supports the following conclusions: (i) Detroit Edison had no net stranded costs in 2000 and $13 million of recoverable net stranded costs attributable to electric Customer Choice in 2001; (ii) Detroit Edison requested recovery of 2001 net stranded costs through the use of excess securitization savings; (iii) Detroit Edison expects to incur additional net stranded costs in 2002 and 2003 as a result of increased electric Customer Choice participation; and (iv) Detroit Edison recommended that a pro-forma or forward looking transition charge be approved for billing during the remainder of 2002 and for 2003 to eliminate the time lag between the occurrence and recovery of net stranded costs inherent in the methodology approved in the December 2001 order. In November 2002, the MPSC Staff and other interveners submitted their 2001 net stranded cost filings. In the fourth quarter of 2002, Detroit Edison recorded a regulatory asset of $21 million, of which $10 million represented an estimate of net stranded costs during 2001, and the remaining balance represented the deferral of environmental expenditures recoverable under PA 141. The effect of recording the regulatory asset increased 2002 earnings by $14 million, net of tax. During the 2003 six-month period, Detroit Edison recorded a regulatory asset of $35 million, of which $12 million represented an estimate of net stranded costs for 2003, and the remainder representing the deferral of environmental expenditures. The effect for the 2003 six-month period was an increase in earnings of $23 million, net of tax.

On July 31, 2003, the MPSC issued an order finding that Detroit Edison had no net stranded costs in 2000 and 2001 and established a zero net stranded cost transition charge for billing purposes in 2003. Although the MPSC found that Detroit Edison had no stranded costs, the MPSC deferred finalizing the methodology for determining stranded cost. However, the MPSC did clarify the inclusion of revenue discounts granted customers under special contracts in the net stranded cost calculation. As a result of the MPSC order and the related clarifying language, we recalculated net stranded costs for 2001, 2002 and the 2003 six-month period. Our revised calculation concluded that the $22 million of net stranded costs recorded as of June 30, 2003 was appropriate.

Additionally, the MPSC determined in its July 2003 order that the full and offsetting credit for securitization and tax charges, and the additional credit on bills equal to the 5% rate reduction realized by full service customers should continue in effect and be funded by savings derived from securitization. The MPSC rejected Detroit Edison’s proposal to utilize a forward looking transition charge and maintained that the use of historical data was more precise. As previously mentioned, the MPSC deferred finalizing the methodology for determining net stranded cost, but indicated they were open to new proposals, including those arising out of an ongoing collaborative process with various interested parties, including Detroit Edison. Detroit Edison expects to file a petition for rehearing of this order.

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Gas Industry Restructuring

Through December 2001, MichCon was operating under an MPSC-approved Regulatory Reform Plan, which included a comprehensive experimental three-year gas Customer Choice program, a Gas Sales Program and an income sharing mechanism. MichCon returned to a GCR mechanism in January 2002 when the Gas Sales Program expired. Under the GCR mechanism, the gas commodity component of MichCon’s gas sales rates is designed to recover the actual costs of gas purchases. In December 2001, the MPSC issued an order that permitted MichCon to implement GCR factors up to $3.62 per Mcf for January 2002 billings and up to $4.38 per Mcf for the remainder of 2002. The order also allowed MichCon to recognize a regulatory asset of approximately $14 million representing the difference between the $4.38 factor and the $3.62 factor for volumes that were unbilled at December 31, 2001. The regulatory asset will be subject to the 2002 GCR reconciliation process. As of December 31, 2002, MichCon has accrued a $22 million regulatory asset representing the under-recovery of actual gas costs incurred. In July 2002, in response to a petition for rehearing filed by the Michigan Attorney General, the MPSC directed the parties to address MichCon’s implementation of the December 2001 order and the impact of that implementation on rates charged to MichCon’s customers. On March 12, 2003, the MPSC issued an order in MichCon’s 2002 GCR plan case. The MPSC ordered MichCon to reduce its gas cost recovery expenses by $26.5 million for purposes of calculating the 2002 GCR factor due to MichCon’s decision to utilize storage gas during 2001 that resulted in a gas inventory decrement for the 2001 calendar year. Although we have recorded a $26.5 million reserve in the first quarter of 2003 to reflect the impact of this order, a final determination of actual 2002 revenue and expenses including any disallowances or adjustment will be decided in MichCon’s 2002 GCR reconciliation case. In addition, we have filed an appeal of the March 12, 2003 MPSC order with the Michigan Court of Appeals. The 2002 GCR reconciliation case was filed with the MPSC in February 2003. A final order in this proceeding is not expected until early 2004.

On July 23, 2003, the MPSC approved an increase in MichCon’s 2003 GCR rate to a maximum of $5.75 per Mcf for the billing months of August 2003 through December 2003. As of June 30, 2003, MichCon has accrued a $81 million regulatory asset representing the under-recovery of actual gas costs incurred. It is expected that the billing of the $5.75 GCR rate will eliminate the under-recovery by year-end 2003.

In December 2001, the MPSC also approved MichCon’s application for a voluntary, expanded permanent gas Customer Choice program, which replaced the experimental program that expired in March 2002. Effective April 2002, up to 40% of MichCon’s customers could elect to purchase gas from suppliers other than MichCon. Effective April 2003, up to 60% of customers are eligible and by April 2004, all of MichCon’s 1.2 million customers can participate in the program. The MPSC also approved the use of deferred accounting for the recovery of implementation costs of the gas Customer Choice program. As of June 2003, approximately 132,000 customers are participating in the gas Customer Choice program.

Minimum Pension Liability

In December 2002, we recorded an additional minimum pension liability as required under SFAS No. 87, “Employers’ Accounting for Pensions,” with offsetting amounts to an intangible asset and other comprehensive income. During the first quarter of 2003, the MPSC Staff provided an opinion that the MPSC’s traditional rate setting process allowed for the recovery of pension costs as measured by SFAS No. 87. Based on the MPSC Staff discussions, management believes that it will be allowed to recover in rates the minimum pension liability associated with its regulated operations. Accordingly, in the first quarter of 2003 we reclassified approximately $641 million ($417 million net of tax) of other comprehensive loss associated with the minimum pension liability to a regulatory asset.

We are unable to predict the outcome of the regulatory matters discussed herein. Resolution of these matters is dependent upon future MPSC orders, which may materially impact the financial position, results of operations and cash flows of the company.

NOTE 5 — EFFECTIVE TAX RATE ADJUSTMENT

Under Accounting Principles Board Opinion No. 28, “Interim Financial Reporting,” we are required to adjust our effective tax rate each quarter to be consistent with the estimated annual effective tax rate.

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This quarterly adjustment had the affect of increasing income tax expense by $107 million and $152 million in the 2003 second quarter and six-month period, respectively, and increasing income tax expense by $25 million and $14 million in the corresponding 2002 second quarter and six-month period. The tax credits associated with our synthetic fuel operations (Note 8) primarily drove the required adjustment. Fluctuations in estimated annual earnings and tax credits resulted in the larger adjustments in the 2003 periods.

NOTE 6 — EARNINGS PER SHARE

We report both basic and diluted earnings per share. Basic earnings per share is computed by dividing net income before accounting changes by the weighted average number of common shares outstanding during the period. Diluted earnings per share assumes the issuance of potentially dilutive common shares outstanding during the period and the repurchase of common shares that would have occurred with proceeds from the assumed issuance. Diluted earnings per share assumes the exercise of stock options, vesting of non-vested stock awards and the issuance of performance share awards. A reconciliation of both calculations for the 2003 and 2002 quarter and six-month period is presented in the table below:

                                 
    Three Months Ended     Six Months Ended  
    June 30     June 30  
   
   
 
    2003     2002     2003     2002  
   
   
   
   
 
(Thousands, except per share amounts)
                               
Basic Earnings Per Share Income (Loss) from continuing operations
  $ (36,700 )   $ 60,800     $ 71,800     $ 252,750  
Average number of common shares outstanding
    167,534       161,124       167,390       160,918  
 
 
   
   
   
 
Income (Loss) per share of common stock based on weighted average number of shares outstanding
  $ (.22 )   $ .38     $ .43     $ 1.57  
 
 
   
   
   
 
Diluted Earnings Per Share Income (Loss) from continuing operations
  $ (36,700 )   $ 60,800     $ 71,800     $ 252,750  
 
 
   
   
   
 
Average number of common shares outstanding shares outstanding
    167,534       161,124       167,390       160,918  
Incremental shares from stock based awards
    369       948       540       794  
 
 
   
   
   
 
Average number of dilutive shares outstanding shares outstanding
    167,903       162,072       167,930       161,712  
 
 
   
   
   
 
Income (Loss) per share of common stock assuming issuance of incremental shares
  $ (.22 )   $ .38     $ .42     $ 1.57  
 
 
   
   
   
 

NOTE 7 — LONG -TERM DEBT

In February 2003, MichCon issued $200 million of 5.7% senior notes due in March 2033. The proceeds were used to redeem a number of debt issues totaling $192 million in March through June 2003.

In April 2003, DTE Energy issued $400 million of 6-3/8% senior notes due in April 2033. In conjunction with this issuance, DTE Energy exchanged $100 million principal amount of existing Enterprises debt due April 2008. The exchange premium and other costs associated with the original debt will be deferred and amortized to interest expense over the term of the new debt.

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In June 2003, DTE Energy redeemed $100 million principal amount of 6.17% Remarketed Notes due in 2038.

NOTE 8 — CONTINGENCIES

Synthetic Fuel Operations

We operate nine synthetic fuel production facilities, seven of which are wholly owned. Synfuel facilities chemically change coal, including waste and marginal coal, into a synthetic fuel as determined under applicable IRS rules. Section 29 of the Internal Revenue Code provides tax credits for the production and sale of solid synthetic fuels produced from coal. To qualify for the Section 29 tax credits, the synthetic fuel must meet three primary conditions: (1) there must be a significant chemical change in the coal feedstock, (2) the product must be sold to an unaffiliated entity, and (3) the production facility must have been placed in service before July 1, 1998. In addition to meeting the qualifying conditions, a taxpayer must have sufficient taxable income to earn the Section 29 credits.

The IRS has suspended issuance of PLRs relating to synthetic fuel projects pending their review of issues concerning chemical change which is the basis for earning Section 29 tax credits. The IRS has announced that it has reason to question the scientific validity of test procedures and results that have been presented in the industry as evidence that the coal feedstock underwent a significant chemical change and is currently reviewing information regarding these test procedures and results. The IRS has indicated that it may revoke existing PLRs that relied on procedures and results under review if it determines that those procedures and results do not demonstrate that significant chemical change has occurred. We have received favorable PLRs from the IRS on 7 of our 9 synfuel plants and have pending requests on the remaining two. The IRS is currently reviewing procedures and results at four of our synfuels plants in conjunction with their normal audits of our federal income tax returns. We believe our synthetic fuel plants operate in accordance with the PLRs. Through June 30, 2003, we have generated approximately $425 million of synfuel tax credits and the credits have been carried forward as alternative minimum tax credits.

We continue to evaluate opportunities to sell interests in some or all of our synfuel projects. Sales of interests in synfuel projects allow us to accelerate cash flow, while maintaining a stable net income base. As the sale of interests in synfuel projects usually requires the reconfirming of the PLR, the timing and number of our synfuel project interest sales has been influenced by the IRS’ suspension of issuing new and reconfirming existing PLRs.

The delay in selling interests in the synfuel projects will result in our capacity to generate more credits than we can utilize. In addition, cool spring and early summer weather, combined with cost and margin pressures, have contributed to lower forecasted taxable earnings. Therefore, we reduced synthetic fuel production by approximately one-half in June 2003 to optimize the tax credits generated from these facilities. Production levels will be assessed weekly and could be increased or decreased depending on various factors, including successful sales of synthetic fuel interests, changes in taxable earnings or the resolution of the IRS review.

We are working aggressively with other industry participants to resolve this issue. Given the complexities of the issues we cannot predict the outcome or timing of the ultimate action of the IRS on this issue. We expect to remain an active participant in the synthetic fuels market.

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Bankruptcies

We purchase and sell electricity, gas and coke to numerous companies operating in the steel, automotive, energy and retail industries. A number of customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. At June 30, 2003, we had approximately $37 million of accounts receivable and approximately $40 million of accounts payable with these bankrupt companies. 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 relating to purchase and sale contracts and record provisions for amounts considered probable of loss. In June 2003, we recorded a reserve of approximately $10 million net of tax for amounts owed to us by a large steel company. We believe our previously 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.

Other

We are involved in certain legal (including commercial matters), administrative and environmental proceedings before various courts, arbitration panels and governmental agencies concerning claims arising in the ordinary course of business. These proceedings include certain contract disputes, environmental reviews and investigations, and pending judicial matters. We cannot predict the final disposition of such proceedings. We regularly review legal matters and record provisions for claims that are considered probable of loss. The resolution of pending proceedings is not expected to have a material effect on our financial statements in the period they are resolved.

See Note 4 for a discussion of contingencies related to Regulatory Matters.

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NOTE 9 — SEGMENT INFORMATION

DTE Energy has the following nine reportable segments. Inter-segment revenues are not material.

                                     
        Three Months Ended     Six Months Ended  
        June 30     June 30  
       
   
 
(in Millions)   2003     2002     2003     2002  
 
   
   
   
 
Operating Revenues
                               
Energy Resources
                               
 
Regulated — Power Generation
  $ 589     $ 660     $ 1,206     $ 1,277  
 
 
   
   
   
 
 
Non-regulated
                               
   
Energy Services
    300       126       530       254  
   
Energy Marketing & Trading
    157       114       464       317  
   
Other
    18       39       69       75  
 
 
 
   
   
   
 
 
Total Non-regulated
    475       279       1,063       646  
 
 
 
   
   
   
 
 
    1,064       939       2,269       1,923  
 
 
   
   
   
 
Energy Distribution
                               
 
Regulated — Power Distribution
    281       302       601       615  
 
Non-regulated
    9       10       14       14  
 
 
 
   
   
   
 
 
    290       312       615       629  
 
 
   
   
   
 
Energy Gas
                               
 
Regulated — Gas Distribution
    289       240       928       841  
 
Non-regulated
    23       23       44       45  
 
 
 
   
   
   
 
 
    312       263       972       886  
 
 
   
   
   
 
Corporate & Other
    3       9       6       9  
Reconciliations and eliminations
    (69 )     (49 )     (167 )     (79 )
 
 
   
   
   
 
Total
                               
 
Regulated
    1,159       1,202       2,735       2,733  
 
Non-regulated (1)
    441       272       960       635  
 
 
 
   
   
   
 
 
  $ 1,600     $ 1,474     $ 3,695     $ 3,368  
 
 
   
   
   
 


(1)   Includes Corporate & Other.

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            Three Months Ended     Six Months Ended  
            June 30     June 30  
           
   
 
(in Millions)   2003     2002     2003     2002  
 
   
   
   
 
Net Income (Loss)
                               
Energy Resources
                               
   
Regulated — Power Generation
  $ 46     $ 56     $ 71     $ 117  
 
 
   
   
   
 
   
Non-regulated
                               
     
Energy Services
    76       30       127       62  
     
Energy Marketing & Trading
    (15 )     (5 )     29       13  
       
Other
    1       (1 )     1       (1 )
 
 
   
   
   
 
   
Total Non-regulated
    62       24       157       74  
 
 
   
   
   
 
 
    108       80       228       191  
 
 
   
   
   
 
Energy Distribution
                               
   
Regulated — Power Distribution
    (16 )     18       (20 )     46  
   
Non-regulated
    (5 )     (4 )     (9 )     (7 )
 
 
   
   
   
 
 
    (21 )     14       (29 )     39  
 
 
   
   
   
 
Energy Gas
                               
   
Regulated — Gas Distribution
    (8 )     (1 )     51       53  
   
Non-regulated
    6       8       14       14  
 
 
   
   
   
 
 
    (2 )     7       65       67  
 
 
   
   
   
 
Corporate & Other
    (122 )     (40 )     (193 )     (44 )
 
 
   
   
   
 
Income from Continuing Operations
                               
 
Regulated
    22       73       102       216  
 
Non-regulated (1)
    (59 )     (12 )     (31 )     37  
 
 
   
   
   
 
 
    (37 )     61       71       253  
 
 
   
   
   
 
Discontinued Operations
    (2 )     7       72       15  
Cumulative Effect of Accounting Changes
                (27 )      
 
 
   
   
   
 
Net Income (Loss)
  $ (39 )   $ 68     $ 116     $ 268  
 
 
   
   
   
 
Diluted Earnings (Loss) per Share
                               
 
Regulated
  $ .13     $ .44     $ .61     $ 1.33  
 
Non-regulated (1)
    (.35 )     (.06 )     (.19 )     .24  
 
 
   
   
   
 
Income from Continuing Operations
    (.22 )     .38       .42       1.57  
Discontinued Operations
    (.01 )     .04       .43       .09  
Cumulative Effect of Accounting Changes
                (.16 )      
 
 
   
   
   
 
Net Income (Loss)
  $ (.23 )   $ .42     $ .69     $ 1.66  
 
 
   
   
   
 


(1)   Includes Corporate & Other.

NOTE 10 — CONSOLIDATING FINANCIAL STATEMENTS

Debt securities issued by Enterprises are subject to a full and unconditional guaranty by DTE Energy. The following DTE Energy consolidating financial statements are presented and include separately Corporate & Other, Enterprises and all other subsidiaries. Enterprises includes MichCon and other non-regulated gas subsidiaries. The other subsidiaries include Detroit Edison and other non-regulated electric subsidiaries.

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DTE ENERGY COMPANY

CONSOLIDATING STATEMENTS OF OPERATIONS

                                           
      Three Months Ended June 30, 2003  
     
 
      DTE                     Eliminations          
      Energy     DTE     Other     and     Consolidated  
      Company     Enterprises     Subsidiaries     Reclasses     Total  
     
   
   
   
   
 
(in Millions)                                        
Operating Revenues
  $     $ 427     $ 1,211     $ (38 )   $ 1,600  
 
 
   
   
   
   
 
Operating Expenses
                                       
 
Fuel, purchased power and gas
          301       226       (34 )     493  
 
Operation and maintenance
    (25 )     94       668       (4 )     733  
 
Depreciation, depletion and amortization
          30       150             180  
 
Taxes other than income
          17       70             87  
 
 
   
   
   
   
 
 
    (25 )     442       1,114       (38 )     1,493  
 
 
   
   
   
   
 
Operating Income
    25       (15 )     97             107  
 
 
   
   
   
   
 
Other (Income) and Deductions
                                       
 
Interest expense
    50       22       79       (19 )     132  
 
Preferred stock dividends of subsidiaries
          3       3             6  
 
Interest income
    (14 )     (4 )     (8 )     19       (7 )
 
Other income
    (76 )     (4 )     (14 )     76       (18 )
 
Other expense
                18             18  
 
 
   
   
   
   
 
 
    (40 )     17       78       76       131  
 
 
   
   
   
   
 
Income (Loss) Before Income Taxes
    65       (32 )     19       (76 )     (24 )
Income Tax Expense (Benefit)
    102       (11 )     (78 )           13  
 
 
   
   
   
   
 
Income (Loss) from Continuing Operations
    (37 )     (21 )     97       (76 )     (37 )
Discontinued Operations
                                       
 
Income from operations
                             
 
Gain on sale
    (2 )                       (2 )
 
 
   
   
   
   
 
 
    (2 )                       (2 )
 
 
   
   
   
   
 
Net Income (Loss)
  $ (39 )   $ (21 )   $ 97     $ (76 )   $ (39 )
 
 
   
   
   
   
 

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DTE ENERGY COMPANY

CONSOLIDATING STATEMENTS OF OPERATIONS

                                           
      Three Months Ended June 30, 2002  
     
 
      DTE     DTE             Eliminations          
      Energy     Energy     Other     and     Consolidated  
      Company     Enterprises     Subsidiaries     Reclasses     Total  
     
   
   
   
   
 
(in Millions)
                                       
Operating Revenues
  $     $ 343     $ 1,162     $ (31 )   $ 1,474  
 
 
   
   
   
   
 
Operating Expenses
                                       
 
Fuel, purchased power and gas
          205       230       (32 )     403  
 
Operation and maintenance
    (24 )     92       555             623  
 
Depreciation, depletion and amortization
          31       149             180  
 
Taxes other than income
          12       69             81  
 
 
   
   
   
   
 
 
    (24 )     340       1,003       (32 )     1,287  
 
 
   
   
   
   
 
Operating Income
    24       3       159       1       187  
 
 
   
   
   
   
 
Other (Income) and Deductions
                                       
 
Interest expense
    43       22       86       (15 )     136  
 
Preferred stock dividends of subsidiary
          2       3             5  
 
Interest income
    (9 )     (3 )     (7 )     13       (6 )
 
Other income
    (102 )     (11 )     (16 )     101       (28 )
 
Other expense
    2       5       23       (3 )     27  
 
 
   
   
   
   
 
 
    (66 )     15       89       96       134  
 
 
   
   
   
   
 
Income (Loss) Before Income Taxes
    90       (12 )     70       (95 )     53  
Income Tax Expense (Benefit)
    22       (4 )     (26 )           (8 )
 
 
   
   
   
   
 
Income (Loss) from Continuing Operations
    68       (8 )     96       (95 )     61  
Discontinued Operations
                7             7  
 
 
   
   
   
   
 
Net Income (Loss)
  $ 68     $ (8 )   $ 103     $ (95 )   $ 68  
 
 
   
   
   
   
 

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DTE ENERGY COMPANY

CONSOLIDATING STATEMENTS OF OPERATIONS

                                           
      Six Months Ended June 30, 2003  
     
 
      DTE                     Eliminations          
      Energy     DTE     Other     and     Consolidated  
      Company     Enterprises     Subsidiaries     Reclasses     Total  
     
   
   
   
   
 
(in Millions)                                        
Operating Revenues
  $     $ 1,321     $ 2,475     $ (101 )   $ 3,695  
 
 
   
   
   
   
 
Operating Expenses
                                       
 
Fuel, purchased power and gas
          928       472       (94 )     1,306  
 
Operation and maintenance
    (90 )     224       1,361       (7 )     1,488  
 
Depreciation, depletion and amortization
          60       317             377  
 
Taxes other than income
          36       148             184  
 
 
   
   
   
   
 
 
    (90 )     1,248       2,298       (101 )     3,355  
 
 
   
   
   
   
 
Operating Income
    90       73       177             340  
 
 
   
   
   
   
 
Other (Income) and Deductions
                                       
 
Interest expense
    94       43       160       (32 )     265  
 
Preferred stock dividends of subsidiaries
          5       7             12  
 
Interest income
    (24 )     (7 )     (16 )     32       (15 )
 
Other income
    (181 )     (9 )     (22 )     181       (31 )
 
Other expense
    15       (1 )     37             51  
 
 
   
   
   
   
 
 
    (96 )     31       166       181       282  
 
 
   
   
   
   
 
Income Before Income Taxes
    186       42       11       (181 )     58  
Income Tax Expense (Benefit)
    137       21       (171 )           (13 )
 
 
   
   
   
   
 
Income from Continuing Operations
    49       21       182       (181 )     71  
Discontinued Operations
                                       
 
Income from operations
                5             5  
 
Gain on sale
    67                         67  
 
 
   
   
   
   
 
 
    67             5             72  
Cumulative Effect of Accounting Changes
                                       
 
Asset retirement obligations
          (2 )     (9 )           (11 )
 
Energy trading activities
          (13 )     (3 )           (16 )
 
 
   
   
   
   
 
 
          (15 )     (12 )           (27 )
 
 
   
   
   
   
 
Net Income
  $ 116     $ 6     $ 175     $ (181 )   $ 116  
 
 
   
   
   
   
 

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DTE ENERGY COMPANY

CONSOLIDATING STATEMENTS OF OPERATIONS

                                           
      Six Months Ended June 30, 2002  
     
 
      DTE     DTE             Eliminations          
      Energy     Energy     Other     and     Consolidated  
      Company     Enterprises     Subsidiaries     Reclasses     Total  
     
   
   
   
   
 
(in Millions)                                        
Operating Revenues
  $     $ 1,138     $ 2,275     $ (45 )   $ 3,368  
 
 
   
   
   
   
 
Operating Expenses
                                       
 
Fuel, purchased power and gas
          741       440       (43 )     1,138  
 
Operation and maintenance
    (49 )     176       1,036       3       1,166  
 
Depreciation, depletion and amortization
          61       308             369  
 
Taxes other than income
          31       143             174  
 
 
   
   
   
   
 
 
    (49 )     1,009       1,927       (40 )     2,847  
 
 
   
   
   
   
 
Operating Income
    49       129       348       (5 )     521  
 
 
   
   
   
   
 
Other (Income) and Deductions
                                       
 
Interest expense
    82       47       168       (25 )     272  
 
Preferred stock dividends of subsidiary
          7       6             13  
 
Interest income
    (16 )     (7 )     (11 )     23       (11 )
 
Other income
    (296 )     (18 )     (18 )     295       (37 )
 
Other expense
    2       6       37       (3 )     42  
 
 
   
   
   
   
 
 
    (228 )     35       182       290       279  
 
 
   
   
   
   
 
Income Before Income Taxes
    277       94       166       (295 )     242  
Income Tax Expense (Benefit)
    9       34       (54 )           (11 )
 
 
   
   
   
   
 
Income from Continuing Operations
    268       60       220       (295 )     253  
Discontinued Operations
                15             15  
 
 
   
   
   
   
 
Net Income
  $ 268     $ 60     $ 235     $ (295 )   $ 268  
 
 
   
   
   
   
 

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DTE ENERGY COMPANY

CONSOLIDATING STATEMENTS OF FINANCIAL POSITION

                                             
        June 30, 2003  
       
 
        DTE                     Eliminations          
        Energy     DTE     Other     and     Consolidated  
(in Millions, Except Shares)   Company     Enterprises     Subsidiaries     Reclasses     Total  

 
   
   
   
   
 
ASSETS
                                       
Current Assets
                                       
 
Cash and cash equivalents
  $ 9     $ 12     $ 82     $     $ 103  
 
Restricted cash
                126             126  
 
Accounts receivable
                                       
   
Customer, less allowance for doubtful accounts
          289       641             930  
   
Accrued unbilled revenues
          20       170             190  
   
Other
    1,329       414       502       (1,875 )     370  
 
Inventories
                                       
   
Fuel and gas
          196       171             367  
   
Materials and supplies
          19       140             159  
 
Assets from risk management and trading activities
          229       123       (3 )     349  
 
Other
    95       95             (76 )     114  
 
 
   
   
   
   
 
 
    1,433       1,274       1,955       (1,954 )     2,708  
 
 
   
   
   
   
 
Investments
                                       
 
Nuclear decommissioning trust funds
                466               466  
 
Other
    6,499       447       279       (6,741 )     484  
 
 
   
   
   
   
 
 
    6,499       447       745       (6,741 )     950  
 
 
   
   
   
   
 
Property
                                       
 
Property, plant and equipment
          3,727       13,810       (3 )     17,534  
 
Less accumulated depreciation and depletion
          (2,098 )     (5,758 )           (7,856 )
 
 
   
   
   
   
 
 
          1,629       8,052       (3 )     9,678  
 
 
   
   
   
   
 
Other Assets
                                       
 
Goodwill
          2,046       40             2,086  
 
Regulatory assets
          63       2,003             2,066  
 
Securitized regulatory assets
                1,571             1,571  
 
Assets from risk management and trading activities
          230       20       (3 )     247  
 
Prepaid pension assets
          177                   177  
 
Other
    23       205       311             539  
 
 
   
   
   
   
 
 
    23       2,721       3,945       (3 )     6,686  
 
 
   
   
   
   
 
Total Assets
  $ 7,955     $ 6,071     $ 14,697     $ (8,701 )   $ 20,022  
 
 
   
   
   
   
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
                                       
Current Liabilities
                                       
 
Accounts payable
  $ 104     $ 452     $ 625     $ (329 )   $ 852  
 
Accrued interest
    23       16       78       (3 )     114  
 
Dividends payable
    87       1       77       (74 )     91  
 
Accrued payroll
          6       35             41  
 
Short-term borrowings
    247       491       903       (1,410 )     231  
 
Current portion of long-term debt, including capital leases
    550       63       131             744  
 
Liabilities from risk management and trading activities
          306       101       (3 )     404  
 
Other
    348       185       15       5       553  
 
 
   
   
   
   
 
 
    1,359       1,520       1,965       (1,814 )     3,030  
 
 
   
   
   
   
 
Other Liabilities
                                       
 
Deferred income taxes
    (370 )     (284 )     1,810       (2 )     1,154  
 
Regulatory liabilities
          137       34             171  
 
Asset retirement obligations
          21       820             841  
 
Unamortized investment tax credit
          21       141             162  
 
Liabilities from risk management and trading activities
          333       14       (2 )     345  
 
Liabilities from transportation and storage contracts
          497                   497  
 
Accrued pension liability
          24       365             389  
 
Nuclear decommissioning
                59             59  
 
Other
    (37 )     158       785       (215 )     691  
 
 
   
   
   
   
 
 
    (407 )     907       4,028       (219 )     4,309  
 
 
   
   
   
   
 
Long-Term Debt
                                       
 
Mortgage bonds, notes and other
    1,880       776       3,201       (186 )     5,671  
 
Securitization bonds
                1,539             1,539  
 
Equity-linked securities
    188                         188  
 
Capital lease obligations
          2       77             79  
 
 
   
   
   
   
 
 
    2,068       778       4,817       (186 )     7,477  
 
 
   
   
   
   
 
Obligated Mandatorily Redeemable Preferred Securities of Subsidiaries Holding Solely Debentures of DTE Energy or Enterprises
          97       174             271  
 
 
   
   
   
   
 
Shareholders’ Equity
                                       
 
Common stock, without par value, 400,000,000 shares authorized, 168,012,997 shares issued and outstanding
    3,076       3,195       2,555       (5,750 )     3,076  
 
Retained earnings
    2,080       (150 )     1,158       (1,008 )     2,080  
 
Accumulated other comprehensive loss
    (221 )     (276 )           276       (221 )
 
 
   
   
   
   
 
 
    4,935       2,769       3,713       (6,482 )     4,935  
 
 
   
   
   
   
 
Total Liabilities and Shareholders’ Equity
  $ 7,955     $ 6,071     $ 14,697     $ (8,701 )   $ 20,022  
 
 
   
   
   
   
 

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DTE ENERGY COMPANY

CONSOLIDATING STATEMENTS OF FINANCIAL POSITION

                                             
        December 31, 2002  
       
 
        DTE                     Eliminations          
        Energy     DTE     Other     and     Consolidated  
(in Millions, Except Shares)   Company     Enterprises     Subsidiaries     Reclasses     Total  

 
   
   
   
   
 
ASSETS
                                       
Current Assets
                                       
 
Cash and cash equivalents
  $ 21     $ 12     $ 100     $     $ 133  
 
Restricted cash
                237             237  
 
Accounts receivable
                                       
   
Customer, less allowance for doubtful accounts
          301       601             902  
   
Accrued unbilled revenues
          119       177             296  
   
Other
    778       150       436       (1,127 )     237  
 
Inventories
                                       
   
Fuel and gas
          219       194             413  
   
Materials and supplies
          19       144             163  
 
Assets from risk management and trading activities
          78       146             224  
 
Other
    22       118       21       (2 )     159  
 
 
   
   
   
   
 
 
    821       1,016       2,056       (1,129 )     2,764  
 
 
   
   
   
   
 
Investments
                                       
 
Nuclear decommissioning trust funds
                417             417  
 
Other
    6,313       436       577       (6,839 )     487  
 
 
   
   
   
   
 
 
    6,313       436       994       (6,839 )     904  
 
 
   
   
   
   
 
Property
                                       
 
Property, plant and equipment
          3,679       14,186       (3 )     17,862  
 
Less accumulated depreciation and depletion
          (2,051 )     (5,998 )           (8,049 )
 
 
   
   
   
   
 
 
          1,628       8,188       (3 )     9,813  
 
 
   
   
   
   
 
Other Assets
                                       
 
Goodwill
          2,080       39             2,119  
 
Regulatory assets
          45       1,152             1,197  
 
Securitized regulatory assets
                1,613             1,613  
 
Assets from risk management and trading activities
          133       19             152  
 
Prepaid pension assets
          172                   172  
 
Other
    11       189       306       (2 )     504  
 
 
   
   
   
   
 
 
    11       2,619       3,129       (2 )     5,757  
 
 
   
   
   
   
 
Total Assets
  $ 7,145     $ 5,699     $ 14,367     $ (7,973 )   $ 19,238  
 
 
   
   
   
   
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
                                       
Current Liabilities
                                       
 
Accounts payable
  $ 73     $ 307     $ 551     $ (284 )   $ 647  
 
Accrued interest
    17       18       83       (3 )     115  
 
Dividends payable
    86       1       76       (73 )     90  
 
Accrued payroll
          9       40             49  
 
Short-term borrowings
    440       450       274       (750 )     414  
 
Current portion of long-term debt, including capital leases
    400       259       359             1,018  
 
Liabilities from risk management and trading activities
          159       126       (1 )     284  
 
Other
    83       104       409             596  
 
 
   
   
   
   
 
 
    1,099       1,307       1,918       (1,111 )     3,213  
 
 
   
   
   
   
 
Other Liabilities
                                       
 
Deferred income taxes
    (339 )     (305 )     1,561       (1 )     916  
 
Regulatory liabilities
          142       37             179  
 
Unamortized investment tax credit
          22       146             168  
 
Liabilities from risk management and trading activities
          199       9             208  
 
Liabilities from transportation and storage contracts
          523                   523  
 
Accrued pension liability
          21       561             582  
 
Nuclear decommissioning
                416             416  
 
Other
    (104 )     146       1,032       (391 )     683  
 
 
   
   
   
   
 
 
    (443 )     748       3,762       (392 )     3,675  
 
 
   
   
   
   
 
Long-Term Debt
                                       
 
Mortgage bonds, notes and other
    1,733       738       3,371       (186 )     5,656  
 
Securitization bonds
                1,585             1,585  
 
Equity-linked securities
    191                           191  
 
Capital lease obligations
          2       80             82  
 
 
   
   
   
   
 
 
    1,924       740       5,036       (186 )     7,514  
 
 
   
   
   
   
 
Obligated Mandatorily Redeemable Preferred Securities of Subsidiaries Holding Solely Debentures of DTE Energy or Enterprises
          97       174             271  
 
 
   
   
   
   
 
Shareholders’ Equity
                                       
 
Common stock, without par value, 400,000,000 shares authorized, 167,462,430 shares issued and outstanding
    3,052       3,191       2,711       (5,902 )     3,052  
 
Retained earnings
    2,132       (131 )     1,185       (1,054 )     2,132  
 
Accumulated other comprehensive loss
    (619 )     (253 )     (419 )     672       (619 )
 
 
   
   
   
   
 
 
    4,565       2,807       3,477       (6,284 )     4,565  
 
 
   
   
   
   
 
Total Liabilities and Shareholders’ Equity
  $ 7,145     $ 5,699     $ 14,367     $ (7,973 )   $ 19,238  
 
 
   
   
   
   
 

43


Table of Contents

DTE ENERGY COMPANY

CONSOLIDATING STATEMENTS OF CASH FLOWS (UNAUDITED)

                                             
        Six Months Ended June 30, 2003  
       
 
        DTE     DTE             Eliminations          
        Energy     Energy     Other     and     Consolidated  
        Company     Enterprises     Subsidiaries     Reclasses     Total  
(in Millions)  
   
   
   
   
 
Net Cash From (Used For) Operating Activities
  $ 238     $ 376     $ (55 )   $ (260 )   $ 299  
 
 
   
   
   
   
 
Investing Activities
                                       
 
Plant and equipment expenditures regulated
          (37 )     (319 )           (356 )
 
Plant and equipment expenditures non-regulated
          (15 )     (29 )           (44 )
 
Proceeds from sale of assets
    610             37             647  
 
Restricted cash for debt redemptions
                110             110  
 
Capital contribution to subsidiary
    (170 )                 170        
 
Other investments
    (523 )     (189 )     7       652       (53 )
 
 
   
   
   
   
 
   
Net cash from (used for) investing activities
    (83 )     (241 )     (194 )     822       304  
 
 
   
   
   
   
 
Financing Activities
                                       
 
Issuance of long-term debt
    281       199                   480  
 
Redemption of long-term debt
    (103 )     (253 )     (444 )           (800 )
 
Short-term borrowings, net
    (192 )     (56 )     629       (565 )     (184 )
 
Capital contribution by parent company
                170       (170 )      
 
Issuance of common stock, net
    21                         21  
 
Dividends on common stock
    (173 )     (25 )     (148 )     173       (173 )
 
Other
    (1 )           24             23  
 
 
   
   
   
   
 
   
Net cash from financing activities
    (167 )     (135 )     231       (562 )     (633 )
 
 
   
   
   
   
 
Net Increase (Decrease) in Cash and Cash Equivalents
    (12 )           (18 )           (30 )
Cash and Cash Equivalents, Beginning of Period
    21       12       100             133  
 
 
   
   
   
   
 
Cash and Cash Equivalents, End of Period
  $ 9     $ 12     $ 82     $     $ 103  
 
 
   
   
   
   
 

44


Table of Contents

DTE ENERGY COMPANY

CONSOLIDATING STATEMENTS OF CASH FLOWS (UNAUDITED)

                                             
        Six Months Ended June 30, 2002  
       
 
        DTE     DTE             Eliminations          
        Energy     Energy     Other     and     Consolidated  
        Company     Enterprises     Subsidiaries     Reclasses     Total  
(in Millions)  
   
   
   
   
 
Net Cash From (Used For) Operating Activities
  $ (340 )   $ 375     $ 153     $ 184     $ 372  
 
 
   
   
   
   
 
Investing Activities
                                       
 
Plant and equipment expenditures regulated