Text

2003 Annual Financial Report for the DTE Energy Company
	ML041190616
Person / Time
Site:	Fermi
Issue date:	04/19/2004
From:	Peterson N; Detroit Edison, DTE Energy
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	NRC-04-0027
	Download: ML041190616 (83)
	v • d • e

Fermi 2 6400 North Dixie Hiy., Newport, Al 48166 Detroit Edison 10CFR50.71(b)

April 19, 2004 NRC-04-0027 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington D C 20555-0001

Reference:

Fermi 2 NRC Docket No. 50-341 NRC License No. NPF-43

Subject:

Annual Financial Report Pursuant to 10 CRF 50.71(b), please find enclosed the 2003 Annual Financial Report for the DTE Energy Company, the parent corporation of the Detroit Edison Company.

Should you have any questions or require additional information, please contact me at (734) 5864258.

Sincerely, Norman K. Peterson Manager - Nuclear Licensing Enclosure cc: w/enclosure D. P. Beaulieu E. R. Duncan NRC Resident Office Regional Administrator, Region III Supervisor, Electric Operators, Michigan Public Service Commission A DTE Energy Company

DTE Energy e;;f~

the energy starts with me

the energy sta rts with mie F~F K Contents 2 3 i s} 'giMi1}.iaThg.i id 4

5 tikf_

liilk i:

0i "We are focused on creating long-term value, not short-term results" tI Photo by Eric Perry RICK FOLTMAN 10 12 ijtif4iW{aI4 "You can depend on us to keep the lights on" A,UYo V

NR4 Aleteorologist "Reliable, prompt, dependable service -

I give it my best every day" 14 "It's exciting to see the possibilities ...

About the Cover: and make them real' "The Energy Starts with Me" is more than a slogan at DTE Energy. It's a mindset our employees embrace that 20 .

reinforces the role each of us plays "Our strategy is intact and working" in the success of our company. 21 tot t [!L441,-l.r,i 1Wl#9tj -jai 38 IQ.,il l W ;>pji, Pictured on the cover, clockwise from left, are: MARIA HENDRICKSON, JEAN LEE, JOE BALOGH, ESMERALDA ZAMARRON, RICK FOLTMAN, CHANDRA LYONS, HARPAL KHATTRA AND ERIC ROCKER.

39 45t1 i(4 k- 2 74 !A'(-ikd'1u i ki-!Jjb Picturedon the back covertfrom top, are:

DIANE GLADSTONE, DEBRA CAIN, JEFF SHARROW 76 at:f~l?[

AND GAIL DONEY. 77 g 4l] tiagiit 3l@

Our

Purpose:

We energize the progress of society.

We make dreams real. We are always here.

Our purpose doesn't change with the business cycle or current trends. It is our reason for being as a company.

Our Mission:

DTE Energy is a premier, full service energy and energy technology company, providing solutions to meet the needs of 21st century customers. We will operate as a fast-paced, progressive, high-performance, value-based organization.

Our mission states what we are today.

. J,1 'i ! k 4 . I Ou r ~Core ValIues:.-

Respect, Customer Service Safety

-Learning

-Business Success Our core values-are guideposts for'-

our behavior and business focus.

PAUL SPURGEON (right),

president, DTEPepTec, Our Vision:

and STEVE JOLIFFE, director, To establish DTE Energy as the premier regional business development, integrated energy company by providing sustained DTE PepTec. earnings growth.

Our vision defines what we want to be.

III 'I I II

DTE Energy Business Segments Energy Resources

--- -_ i

-_I - _--

_ 3 19;1 EnergyDisriutint 1

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m.

I

Energy Resources Regulated Power Generation Non-Regulated Energy Services Energy Marketing

&Trading Coal Services and Biomass

Ener---Distribution : -.::

Regulated Power Distribution I

Non-Regulated , 1 . .6 I___._31.0 I Distributed _ _*

I * *I Generation _ .

I I ** I

I .

-Energy Gas Regulated I Gas Distribution _ . , . . s_

I ._ 0_ _. 1 11 I.l I. __I I 5 0._l Non-Regulated

s I . 0.

Gas Production * ; g , m . *_ .

and Gas Storage, 33 .0 13.i._

Pipelines & Processing S. S. .3 * .05 II I .

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Financial Highlights (Dollars in Millions, Except Per Share Amounts) 2003 2002 % Change Operating Revenues Regulated Energy Resources $ 2,448 $ 2,711 (101%

Energy Distribution 1,247 1,343 (7)%

Energy Gas 1,498 1,369 9%

Non-Reaulated 1,848 1;306 42 %

$ 7,041 $ 6,729 5%

Net Income Regulated Energy Resources $ 235 $ 241 (2)%

Energy Distribution 17 111 (85)%

Energy Gas 29 66 (56)%

Non-Regulated 256 224 14 %

Corporate & Other (57) (56) 2%

480 586 (18K%

Discontinued Operations 68 46 48 %

Cumulative Effect of Accounting Chances (27) - -

$ 521 $ 632 (18)%

Diluted Earnings Per Share 1 Regulated Energy Resources $ 1.40 $ 1.46 (4)%

Energy Distribution 0.10 0.67 (851%

Energy Gas 0.17 0.40 (58)%

Non-Regulated 1.52 1.36 12 %

Corporate & Other (0.34) (0.34) -%

2.85 3.55 (20)%

Discontinued Operations 0.40 0.28 43 %

Cumulative Effect of Accounting Change (0.116) - - .;Z

$ 3.09 $ 3.83 0191 Other Financial Information Dividends Declared Per Share $ 2.06 $ 2.06 -

Dividend Yield 5.2% 4.4% 18%

Average Common Shares Outstanding (Millions)

Basic 168 164 2%

Diluted 168 165 2%

Book Value Per Share $ 31.36 $ 27.26 15 %

Market Price at Year End $ 39.40 $ 46.40 (15)%

Total Market Capitalization $ 6,643 $ 7,770 (15)%

Capital Expenditures $ 751 $ 984 (24)%

Total Assets $ 20,753 $ 19,985 4%

Cumulative Total Return percent 60- 53.5% _ OTE Energy S&P Electric Index 50 11111 40 34.9%

30 20 17.6%

10 4.0% 5.4%

0 -- -

-10

-20 _ -12.3%

1999-2003 2000-2003 2001-2003 Despite a weak performance in 2003, we have achieved attractive long-term investment returns.

oOI

Letter to Shareholders "We are focused on creating long-term shareholder value."

to $3.83 per share in 2002. Our stock price also declined - 15 percent.

The biggest driver affecting our financial performance in 2003 - and that remains a threat in 2004 - is loss of revenue due to Michigan's Electric Choice program, along with uncertainty surrounding our pending electric and natural gas rate case filings.

Public Act 141, which established the Choice program in 2000, was written as a transition toward total electric deregulation in Michigan. It was supposed to deliver electric choice, jobs and affordable, reliable electricity for Michigan residents and businesses, and financially healthy utilities. But Choice is not working. Electricity has not been a major factor in attracting new businesses to the state. Rather than real competition, the state's existing utilities are handcuffed with requirements not placed on alterna-It was a difficult year for DTE Energy. tive energy suppliers. The out-of-state TONY EARLEY, electricity resellers are the only chairmanand We faced challenges on many fronts.

Most of them were driven by external ones profiting.

chief executive officer factors. And in all cases, we tackled These resellers offer market-based the challenges head-on. rates with special incentives from the In 2003, the economy remained weak. state, while utility rates remain We battled an ice storm, two windstorms regulated. Customers have the option and a historic blackout. Summer to switch back and forth between the weather was milder than normal. lower of the two rates. Yet utilities Production from our synthetic fuels must have capacity to provide service business was temporarily curtailed to each and every person in their while the Internal Revenue Service service territories, whether it's our conducted an industrywide review. customer or someone who has left Natural gas prices jumped. And pension us. In addition, Michigan utilities and health care costs continued to rise. must cover all costs of maintaining the state's electric system and carry As a result, our earnings per share a reserve margin of about 15 percent were a disappointing $3.09, compared of electric power to cover unexpected I

I =__

events. Out-of-state energy providers are not required to maintain the same level of reserve or support system maintenance.

While PA 141 was intended to foster competition, it has created an artificial market that favors resellers. Energy STEPHEN BRADLEY, marketers are "cherry picking" our SOC central high margin customers, leaving system supervisor residential and small commercial customers to foot the bill. As a result, residential rates could increase by as provisions of PA 141. We hope to see much as 30 percent unless the Choice further progress when a final order program is changed. on Detroit Edison's electric rate case is issued late in the year. The Michigan So far we've spent more than legislature is also studying how to

$80 million to implement Choice reshape the Choice program. You can and have not been allowed to recover learn more about this critical issue at these costs. In addition, Choice sales www.clearMichigan.com.

took $120 million out of our generation business in 2003. It will take an As we push for reform, we await estimated $200 million out in 2004 responses from the MPSC on the and even more in 2005, if nothing electric and gas rate cases we filed is done. in 2003. Neither Detroit Edison nor MichCon has requested a rate increase Recently, the Michigan Puplic Service in more than a decade, and we need Commission (MPSC) took the first these increases to cover the effects steps toward implementing key of 10 years of inflation.

71_ , -- :

I I I I The Monroe Power Plant is thefourth Detroit Edisonplant to receive IS014001 environ~mental management certification..

ThMe others are the St.Clair,Belie River and Thenton power plants.

processing particles of coal into a product that can be burned to produce energy. We earn tax credits for the production of synfuel. Since we earn more credits than we can use, we generate cash by selling partnership interests in the units.

Interests in two of our nine units were sold in 2002. Interests in three additional facilities were sold in 2003, The timing related to our rate cases and one other unit in January 2004.

is creating even more pressure on We intend to continue to sell down our financial situation. We received interests in all our facilities throughout interim rate relief in late February and 2004. This business generated expect a final decision by September.

$197 million in net income for the For our gas case, we're projecting company in 2003 and is expected to interim rate relief in time for the generate between $150 million and 2004-2005 heating season, with full

$190 million in 2004.

rate relief sometime in early 2005.

Another highlight was the success Our financial picture is also complicated of our 2003 pilot project to test a by the rate caps that are in effect on proprietary waste coal recovery the electric side of our business.

technology. Our new DTE PepTec The rate cap won't expire until 2005 subsidiary uses a unique system to for small commercial and industrial clean waste coal discarded by previous customers, and 2006 for residential mining and processing operations. The customers. So the beneficial impacts cleaned coal is then burned at power will not be fully realized for at least plants to generate electricity. Currently, two years. We believe that, ultimately, we're operating one waste coal we'll be allowed a fair return for recovery plant, and we intend to site our utilities. When that happens, a number of new projects in 2004.

DTE Energy will be well positioned You can read more about this new for the future.

business on Page 14.

Despite the obstacles we encountered Our efforts to keep the environment in 2003, there were many bright spots.

clean received national recognition In October, after a six-month review when President George W. Bush by the IRS, we increased our synfuel selected the Monroe Power Plant to production. Synfuel is made by deliver a major environmental speech.

III i

"Since 1974, the power generated As we move forward, we are focused here has increased 22 percent," Bush on improving how we manage the said, referring to the Monroe plant. integration of our people, tasks, "You've created more power so information and technology. Driving more people can live a decent life. this change is DTE2, a program And yet, particulate matter emissions focused on revamping old processes have fallen by 80 percent." to standardize and optimize them across the enterprise. In essence, we Our company also earned public want to reinvent the company using recognition for its restoration efforts best-in-class processes and world-during the August 14 blackout. Just class software to support the changes.

38 hours4.398148e-4 days 0.0106 hours 6.283069e-5 weeks 1.4459e-5 months after the lights went off, Our target completion date is 2006.

power was again available to all of While 2004 will be another tough our customers, without resorting to year, we're positioning our company rolling blackouts. The North American for long-term success. We're focused Electric Reliability Council singled out on six corporate priorities:

DTE Energy's "extraordinary work" in bringing our system back on line

Achieve Electric Choice reform, so quickly.

Achieve success in pending electric This was a testament to the hundreds and gas rate cases, of employees who worked with

Continue growth of our intense focus, under very difficult non-regulated businesses, circumstances, to get the lights back on in Michigan swiftly and safely. I'm

Maintain cash and balance sheet extremely proud of their teamwork, strength, creativity and commitment to our

Continue to build depth in our In 2003, the company customers. Our response to the management team and cultivate a battled an ice storm, blackout is covered in more detail performance-based work culture, two windstormns and on Page 10. a historic blackout

Meet all Sarbanes-Oxley We implemented a series of cost and internal controls and cash flow initiatives companywide of /;

governance requirements.

that were tremendously effective.

These efforts helped us maintain the We are developing leaders who have integrity of our balance sheet. We the character, values, knowledge and will continue down this path in 2004. experience to guide our company in See the letter from our chief financial the future. They model our core values officer, on Page 20, to review our and are attuned to the interests of our financial objectives. shareholders. In fact, approximately 4.5 percent of DTE Energy stock is The DTE Energy Operating System owned by employees.

is helping us improve processes, Why invest in DTE Energy?

eliminate waste and reduce costs.

In 2003, we realized savings of

We maintain a balanced model approximately $45 million through of regulated and non-regulated various Operating System improve- businesses with varying risk/return ments. Our target for 2004 is profiles. This diversity provides

$100 million. stability to our earnings stream.

II I . I 'I'

r r '

II FI

,I From the left, I ERIC ROCKER, 1,

I leader,distribution; i CATHERINE ZITZELBERGER, t

II journeyman, lineman, distribution; II VERN AITSON, leader, distribution.

Our current stock price reflects uncertainties that should be resolved in the next six to nine months as we achieve regulatory clarity.

We provide attractive multiyear investment returns. Our total return to shareholders over the past three years was 17 percent.

We provide a solid dividend with a high yield: 5.2 percent.

Basic utilities form our core We are focused on creating lasting operations. Traditionally, utilities shareholder value. Let me assure are allowed to earn a fair return and you that I take this commitment provide a stable base of earnings very seriously, as does the entire for shareholders. Ultimately, DTE Energy leadership team.

Detroit Edison and MichCon will, too. Thank you for your continued support.

We have a consistent, successful non-regulated strategy. It is linked to our core skills and assets, and is focused on creating value for our shareholders.

We are committed to maintaining a healthy balance sheet and a Anthony E Earley, Jr.

strong investment grade Chairman and Chief Executive Officer credit rating. March 1, 2004 II, I II

Detroit Edison "You can depend on us to keep the lights on."

Detroit Edison has powered the growth of Southeastern Michigan for more than a century. In its earliest years, the company established a tradition of safe, reliable service that continues to this day.

We take our commitment to customers very seriously. Nowhere was this more evident than in our efforts to restore power quickly and safely following the August 14 blackout that left virtually all of Detroit Edison's 2.1 million customers in the dark.

Twenty-six of our 28 major generating units went down, as did Southeastern Michigan's electric transmission and distribution systems.

Hundreds of employees worked long hours, at times in the dark, under incredibly tough conditions, to inspect, repair and return our system to normal. Even though they had no power at their homes, and limited ways to communicate with us, systems. Power plant turbines were From left, RICH ALLEN, employees showed up at our plants, rotated by hand to keep them from generalforeman, reliability our substations and our offices warping. and JOSEPH BALOGH, senior production engineer, without being called. Monroe Power Plant.

Our 85 diesel and gas-fired peakers -

We were faced with some of the at 19 separate Detroit Edison locations most basic challenges - from keeping -were instrumental in powering up company vehicles fueled, to providing the system. Typically, these facilities food and water to our workers, to are used during peak demand to maintaining communication at our supplement our power generation.

locations without the use of simple But they played an even more critical office equipment, such as fax role during the blackout. They machines, pagers and phones. provided the initial power to light our plants, and later, to restart the boilers, Scarce resources had to be quickly coal mills and turbines that produce reallocated to manage the early hours our electricity.

of the blackout. Generators normally used in manholes and tunnels were Throughout the blackout, hundreds deployed to power Emergency of plant operators, engineers, Headquarters and our computer technicians, maintenance personnel I~1 II ,

From the left, Soc operators, GARY JONES, senior central system supervisor; PETER HEIDRICH. senior centralsystem supervisor;,..

JEFF SHARROW, central sysem supermsor.

and MICHAEL SAKSA, operationsmanager

-<-U .....

Detroit Edison

Ninth largest electric utility in the U.S.

2.1 million customers spanning 7,600 square miles in Southeastern Michigan

Generates more than 11,000 megawatts (MW) of electricity

Operates one nuclear power plant, nine coal-fired plants, owns 85 peaking generators at 19 locations, 49 percent of one hydroelectric pumped storage facility and 663 distribution substations

Maintains 41,000 miles of power lines and nearly 1million utility poles

Sold 44,000 gigawatt hours (gWh) of electricity in 2003

$3.7 billion in revenue in 2003 and others worked to ensure that helicopters, equipped with thermal power was restored without short- imaging cameras, flew overhead circuiting the system. looking for hidden damage that could cause trouble. They were supported Our System Operations Center (SOC) by dozens of ground teams.

developed and managed a complex and fluid restoration plan, responding Just 38 hours4.398148e-4 days 0.0106 hours 6.283069e-5 weeks 1.4459e-5 months after the lights went off, to urgent needs first. When the City power was once again available to all of Detroit Water and Sewerage of our customers, without resorting to Department had insufficient back-up rolling blackouts. Our efforts did not power to keep operating, the SOC go unnoticed.

team improvised. It remapped our restoration plan and returned key city Residential customers' overall facilities to service well in advance of satisfaction with Detroit Edison our original schedule. increased 7 percent after the blackout.

Eighty-one percent of our residential In addition, all 40,000 miles of customers, and 87 percent of our small transmission and distribution lines and medium commercial customers, in Southeastern Michigan needed to gave Detroit Edison positive ratings be re-energized and monitored. Four on our restoration work.

I,, I ' s II

MichCon "Reliable, prompt, dependable service

- I give it my best every day.

After 11 years in the business, MichCon to provide quality, unbiased DWAIN WRIGHT (left) and MichCon's Paul Cyburt will tell you service. After all, MichCon has offered JEAN JACKSON, service that appliances seem to break down appliance repair services for more consumption Tech 1 at the most inconvenient times. Your than 100 years.

furnace in the dead of winter. The water heater just when you're ready HPP customers understand the value to take a shower. Your central air of dependable service. Last winter conditioning on the hottest day of the on a bitter Friday night, one such year. And when that happens, you customer came home to a cold house.

want it fixed, NOW. She called MichCon's hotline number and by 8:30 a.m. the next morning, "People are so relieved when they see her home was warm again - with no me at their front door:' says Cyburt, repair charges.

who repairs gas appliances under the company's optional Home Protection She writes: "If I had not had my Plus (HPP) program. "It's a great Home Protection Plus plan, first, feeling to know I'm making someone's I would have had to search theYellow day a little bit better." Pages hoping I selected a trustworthy furnace repair company. Next, if they Gas ControlRoom (from left)

Often the simplest repair means answered their phone on a Friday DIANE GLADSTONE, supervisor; inconvenience, discomfort and night, chances are I would have been DAVE CESARZjunior controller; maybe hundreds of dollars. But for connected to a voice mail or a generic TIM JAMES, seniorcontroller those who subscribe to the HPP, one toll-free call brings an authorized technician to their home to take care of gas and electric repairs, and all covered parts and labor are free.

As part of MichCon's merger with DTE Energy, an opportunity was identified to combine Detroit Edison's program with MichCon's. The consolidation was completed in 2003 under a new, improved plan now owned and I administered by MichCon.

Today, approximately 160,000 consumers, or 8 percent of our total customer base, depend on the security and peace of mind of HPP.

Close to 60 percent of participants are 65 years or older, and 20 percent have annual household incomes below

$25,000. These customers trust

r MlichCon customer care representatives (from left) CHANDRA LYONS, MARIA HENDRICKSON and MICHAEL COMBS.

gest natural gas utility in the U.S.

on customers in Michigan of natural gas sales 48 storage wells representing 12 percent of the nation's gas capacity pipeline in our system to go around the world 1.5 times.

ion in 2003 revenue PAUL CYBURT, MichCon answering service. Probably no passed SB 612, which if it becomes field service technician. repairman would come until Monday. law, would allow utilities to continue But if a serviceman came on Saturday, offering appliance repair, subject to I would be charged with a bloated certain conditions.

service call and quadruple prices for the repairs, penalizing me for having DTE Energy supports SB 612 as the misfortune of a furnace igniter passed by the Senate, as fair and dying on a weekend. I have been balanced legislation. It protects the down that road before.' interests of utility customers and individuals in need of appliance Over the years, there have been repair services, while maintaining periodic legal challenges to utilities a competitive market. In addition, being involved in appliance repair. MichCon's HPP program helps Most recently, the legal concerns support Michigan's economy by have focused on whether utility-run providing good paying jobs for our appliance repair programs are in employees and for independent violation of Michigan's Electric Code contractors who work with us as of Conduct. In an attempt to end the strategic partners.

controversy, the Michigan Senate has EL/A D 1= oiu

Growth "It's exciting to see the possibilities . .

and make them real."

Who would have imagined that We had a number of successes in Our on-site energy billions of tons of waste coal in refuse 2003. On-site energy projects - such businessprovides Detroit ponds across the country could be as pulverized coal injection, power- MetropolitanAirport's recycled into fuel for power plants. house operations and cogeneration Mlidfleld Terminal complex with electricity as well as

- provided net income of $9 million.

Building on our vast knowledge of hot waterfor heating and This business should grow substantially chilled waterfor cooling.

coal markets and long-standing in 2004, as a result of a new on-site relationships with coal companies, energy deal we expect to close with a it was the logical next step for Fortune 100 company in the first half DTE Energy. Our new proprietary of 2004. DTE Energy Services will PepTec9 Process is the only technology own and operate several of its on-site we know of that can produce a high energy facilities. These operations will quality coal product from waste provide steam, power distribution, coal typically discarded. chilled water, compressed air and DTE PepTec, a newly formed subsidiary wastewater treatment for sites in of DTE Coal Services, recently began Michigan, Indiana and Ohio.

operating its first waste coal recovery We are also capitalizing on the growing facility in Ohio, and is targeting a need for asset management, and number of new projects for 2004. operations and maintenance services If this business develops as we for creditors that hold generation anticipate, it could generate between assets of distressed companies. DTE

$20 million and $40 million in annual Energy Services recently announced net income by 2008. its first project of this kind, managing Although we managed growth capital a power plant in Connecticut.

very carefully in 2003 - and will continue On the gas side, we are rebalancing to do so in 2004 -we remain committed our midstream portfolio. In 2003, we to growing our non-regulated businesses increased our equity ownership in with high potential investments like the Vector pipeline to 40 percent and DTE PepTec. sold our 16 percent interest in the Our focus is on pursuing the very best Portland pipeline for a gain. Vector opportunities - those that are low risk, is a 348-mile interstate pipeline that require low up-front capital, and build supplies and transports natural gas upon our core skills and assets. from producing regions of the United States and western Canada to growing JASON SANCHEZ, Staying true to this strategy helped markets in the Midwest and Northeast, seniorpower marketer, DTE Energy's portfolio of non-regulated as well as eastern Canada. Energy YMading.

businesses remain a strong contributor to earnings in 2003. Net income In fact, Vector connects to the increased 14 percent to $256 million, DTE Energy Gas storage facilities in with a range of $194 million to Michigan. We plan to increase our

$249 million projected for 2004. storage capacity more than 10 percent I iiiiii'm m

ART DAVIS, senior compression station operator, DTE Energy Gas.

-.I LL Michigan to take advantage of Antrim consolidation and coal bed methane opportunities. DTE Energy is the largest producer of Antrim shale gas in Michigan and accounts for about 16 percent of the state's Antrim production. We are also exploring coal bed methane as a large, untapped resource, principally in the Midcontinent region.

Our non-regulated gas businesses STEVE JOLIFFE (left) by 2006. We believe natural gas storage contributed $29 million to earnings director, business has tremendous growth potential and in 2003 (including a $10 million gain development, we intend to enhance our existing on the sale of our Portland interest).

DTEPepTec, capabilities via low capital expansions. These businesses include gas storage, and PAUL SPURGEON, production, and pipelines and president, DTEPepTec. At the same time, we're exploring processing operations.

ways to grow our upstream gas business. Currently, we produce Our synthetic fuel business is also 25 Bcf of gas annually from more than expected to continue generating 1,800 wells in northern Michigan, and healthy income and significantly higher have gas reserves of 350 Bcf. But levels of cash. We own nine units at unconventional gas production holds eight facilities and have sold interests promise, too. In fact, we created in five units. We expect to sell interests DTE Gas Resources in 2003 to explore in the rest of the units in 2004, adding this market. an estimated $330 million to $350 million to cash flow. We are targeting We are using our position as the second production of 13 million to 17 million largest, lowest cost well operator in tons of synfuel in 2004, representing 2OL4= I '

- .I_

approximately $150 million to development and marketing of

$190 million in net income. energylnow distributed generation systems and services, while we Recently, DTE Energy has capitalized streamline our operations to focus on on a tight market for industrial coke the most attractive market segments.

to enhance the value of our coke Our company is viewed as a leader in GARY QUANTOCK, vice president batteries. We expect this business this industry. and manager- assets, line to contribute pretax cash flows DTE Energy Services.

of $40 million - a substantial increase photo byAnzeen 11owrani over prior year levels.

We will look for opportunities to Cot_ !w__A expand our existing fleet of 31 biomass projects and leverage this expertise into new applications. In 2003, DTE Biomass Energy began C31 _4!S commercial operation of its second facility to produce pipeline-quality natural gas from landfill gas.

We will continue our strong and disciplined marketing and trading of gas, power, coal and emissions credits. In 2003, our sixth year of operation, DTE EnergyTrading earned

$32 million in net income. Our intent is slow growth with a strong focus on physical marketing, primarily in the regions served by DTE Energy.

In addition, we will continue to support DTE EnergyTechnologies' , " " :_ I

- I Photo by Eic Perry _

I . ,7- J. !- -- -- - - , -- Z-- --

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rfr ;

t4milc.k f." . 'U BRYAN LAWRENCE, landfill gas production manager, DTEBiornassEnergy

I Board of Directors I t

Terence E.Adderley, 70, is chairman and chief executive office Theodore S. Leipprandt, 70, is owner of Leipprandt Orchards and Kelly Services Inc. He was elected its president and CEO in 191 retired president and chief executive officer of Cooperative and has served as the company's chairman since 1998. He was Elevator Co. He was elected to the DTE Energy Board in 1990 elected to the DTE Energy Board in 1987 and will retire in 2004. and will retire in2004. (A,N,P)

IC,E,F,O)

John E.Lobbia, 62, retired as chairman and chief executive Lillian Bauder, 64, is vice president of Corporate Affairs for Ma:sco officer of DTE Energy and Detroit Edison in 1998. He joined the Corporation and president of the Masco Corporation FoundatioiIn . company in 1965 and has served on the DTE Energy Board since since 1996. She joined DTE Energy's Board in 1986. 1988. (F,N)

(A,E,N,P)

Gail J. McGovern, 52, is professor of management practice at the David Bing, 60, is chairman of the board of Bing Group Inc., a Harvard Business School since 2002. Prior to that she was position he has held since 1980. Mr. Bing joined the DTE Energ' president of Fidelity Personal Investments, a unit of Fidelity Board in 1985. (O,P.S) Investments of Boston. Ms. McGovern was elected to the DTE Energy Board in 2003. IF)

Anthony F.Earley, Jr., 54, is chairman, president, chief executive officer and chief operating officer of DTE Energy Eugene A. Miller, 66, is retired chairman, president and chief since 1998. He joined DTE Energy in 1994 as president and executive officer of Comerica Incorporated and Comerica Bank.

chief operating officer, the same year he was elected to the Mr. Miller joined the DTE Energy Board in 1989. (C,E,F,0)

DTE Energy Board. (E)

Charles W.Pryor, Jr., 59, is president and chief executive officer of Allan D.Gilmour, 69, is vice chairman Ford Motor Co. Urenco Inc. Prior to that he served as chief executive officer of He was elected to the DTE Energy Board in 1995. (C,E,F,O,S) Utility Service Business Group, BNFL which includes the Westinghouse Electric Company. Dr. Pryor joined the DTE Energy Alfred R.Glancy III, 66, former chairman and chief executive of Board in 1999. (N) of MCN Energy Group, served inthat position from 1988 until 20 He was chairman of MichCon from 1984-2001 and served as its Josue Robles, Jr., 57, is executive vice president, chief financial CEO from 1984-1992. He joined DTE Energy's Board in2001. officer and corporate treasurer of USAA, a worldwide insurance (F,P) and diversified financial services company. He joined USAA after a 28-year military career, during which he served as the U.S.

Frank M. Hennessey, 65, is chairman and chief executive office Army's budget director at the Pentagon. General Robles was Hennessey Capital. Prior to that he was chairman of EMCO Ltd elected to the DTE Energy Board in 2003. (A) and vice chairman and chief executive officer of MascoTech.

He served on the board of MCN Energy since 1988 and joined tI Howard F.Sims, 70, is chairman and chief executive officer of Sims DTE Energy Board in 2001. (A,P) - Design Group Inc. He served on the board of MCN Energy since 1988 and joined the DTE Energy Board in 2001. (C,N)

From the left, JOHN LOBBIA, ALLAN GILMOUR, EUGENE MILLER, TERENCE ADDERLEY, HOWARD SIMS, CHARLES PRYOR, GAIL MCGOVERN.

Seated,from the left, THEODORE LEIPPRANDT, LILLIAN BAUDER, FRANK HENNESSEY, ANTHONY EARLEY, JOSUE ROBLES, DAVID BING, ALFRED GLANCY.

Committee Membership:

A - Audit C- Corporate Governance, E- Executive, F- Finance, N - Nuclear Review, 0 - Organization and Compensation, P- Public Responsibility, S- Special Committee on Compensation 21I, I ', I,

-- - -- - - ~

DTE Energy Executive Committee A credible team of officers leads our way Ron A.May, 52, is senior vice president of DTE2. He joined Detroit Edison, a subsidiary of the company, in 1984 as director of planning and control of nuclear administration. He held a series of increasingly responsible positions, Gerard M.Anderson, 45, is president and chief including manager of service center operations; operating officer of OTE Energy Resources Group. assistant vice president, energy delivery; and He was named to his present position in 1998. vice president energy distribution. He was Previously he was executive vice president of named to his current position in 2003.

DTE Energy. Anderson joined the company in 1993 from McKinsey & Co., where he was a consultant in energy and finance.

Susan M. Beale, 55, is vice president and corporate secretary. She joined Detroit Edison, a subsidiary of the company, as an attorney in 1982. Beale was named corporate secretary in 1989 and was elected vice president in 1995.

She came to DTE Energy after four years with the legal staff of Southern California Edison, David E.Meador, 46, is senior vice president and and two years with Consumers Power. chief financial officer. He joined DTE Energy in 1997 as vice president and controller and Robert J. Buckler, 54, is president and chief oper- was elected to his current position in 2001.

ating officer of DTE Energy Distribution Group. In addition to controller, Meador served as He joined the company in 1974 and was named to senior vice president and treasurer. Prior to his current post in 1998. He has held numerous joining DTE Energy, he served as controller of positions throughout the organization including Chrysler Corp.'s MOPAR auto parts division and power plant engineering, construction and opera- as a senior auditor for Coopers & Lybrand's tion, fuel supply management, transmission and Detroit office.

distribution operation, customer service, market-ing and strategic planning.

Anthony F.Earley, Jr., 54, is chairman, president, chief executive officer and chief operating officer (COO) of DTE Energy. He joined _ Bruce Peterson, 47, is senior vice president and Detroit Edison in 1994 as general counsel. Prior to joining DTE Energy in president and COO and that 2003, he was a partner in the Washington, D.C.

same year was elected a company director. office of Hunton & Williams, a national law firm He was elected to his current position in 1998. specializing in energy industry matters. He spent Before joining DTE Energy, Earley served as 14 years with the firm, focusing on energy and president and COO of Long Island Lighting infrastructure project finance transactions, Company where he had worked since 1985. acquisitions and divestitures, and related contract structuring and regulatory matters.

Stephen E.Ewing, 59, is president and chief operating officer of DTE Energy Gas Group. He joined the company in 2001 from MCN Energy, S. Martin Taylor, 63, is senior vice president where he served as its president and chief of human resources and corporate affairs.

operating officer, and president and chief He joined Detroit Edison, a subsidiary of the executive officer of its primary subsidiary, company, in 1989 as vice president of corporate MichCon. Ewing joined MichCon in 1971, and public affairs after serving as president of holding executive positions in corporate New Detroit, Inc., the first and largest urban planning, personnel, administration and coalition in the country. Earlier in his career, customer service. he worked as a corporate lawyer in Chicago, and then served on the cabinets of two former Michigan governors.

18 2003DTEEnergyAnnual Report

d Officers[ - I Michael C.Porter Pamela A. Biesecker Vice President Vice President Corporate Tax Communications p -

,. ~

[L I

i, I Robert A.Richard Daniel G.Brudzynski tVice President Vice President and I' I Fossil Generation Controller

=

Michael E.Champley Frederick E.Shell Senior Vice President Vice President Regulatory Affairs Corporate and i

Governmental Affairs Lynne Ellyn Senior Vice President FI i Larry E.Steward and Chief Information Vice President Officer l Human Resources 1.

Douglas R.Gipson i Harold Gardner Executive Vice ASenior Vice President and Chief t President Nuclear Officer l Gas Operations Detroit Edison t Joyce V.Hayes-Giles Senior Vice President Customer Service Detroit Edison and Select Subsidiary Presidents MichCon F 7 Thomas A. Hughes Vice President and I General Counsel Detroit Edison Randall D.Balhorn President DTE Energy Trading Nick A. Khouri G.Paul Horst Vice President and President Treasurer DTE Energy Technologies Steven E.Kurmas Senior Vice President Distribution Curtis T.Ranger President DTE Biomass Energy asa Barry G.Markowitz President DTE Energy Services r

Operations William T.O'Connor Gerardo Norcia Richard L.Redmond, Jr. President Vice President President Nuclear Generation DTE Gas Storage, DTE Gas and Oil I Pipelines &

Detroit Edison Processing Sharon E.O'Niel Fred L Shusterich Vice President President Evan J. O'Neil DTE2 Midwest Energy President Resources (MERC) DTE Coal Services Iii I II

- _J__

Letter from the Chief Financial Officer "Our strategy is intact and working.

We will stay the course."

Was 2003 a good year for DTE Second, we want to maintain a solid Energy? The answer is yes and no. investment grade rating and strong We had six great years of delivering underlying cash flows. We are on our financial commitments and the committed to preserving our current stock price in 2002 and early 2003 credit rating and have taken steps reflected that performance. In to strengthen the balance sheet. This January 2003, we hit an all-time high. remains a top priority and is directly Then uncertainty surrounding our tied to successful resolution of the rate rate cases and Michigan's Electric cases. Our synfuel business is also Choice program put the brakes on expected to contribute significantly, our performance. We ended the year generating cash of $1.8 billion in the with disappointing results. next five years.

No one is happy when a company Third, we will continue to pursue goes through a period like we did in conservative and sound financial 2003. The majority of our business is policies. We strive to be transparent regulated by the state of Michigan. in everything we do. We focus on During stable economic times, rate shareholder value creation.

cases aren't necessary. Unfortunately, these are not stable times. Fourth, we plan to continue paying the current dividend.

DAVE MEADOR, senior Our two utilities are working through You can trust what you read on these vice presidentand chief rate cases that will determine their financial officer future revenue levels, and the pages. We will not compromise on Michigan Electric Choice program our core values. While we pride our-needs to be fixed. Our utilities' earn- selves on our business ethics and system ings will remain depressed until these of internal controls, we are using the issues are resolved. Fortunately, our requirements of Sarbanes-Oxley to non-regulated businesses are doing redouble our efforts in this area.

very well. During this period of regulatory Our strategy is intact and working, uncertainty, we will continue to do what and we will stay the course. we do well - strive for shareholder value, work to become more efficient, Let's review our financial objectives. and deliver high quality services to our First, we want to deliver total share- customers. A deep commitment to holder return in the top fifty percentile our business strategy and financial of our industry. We didn't meet that objectives keeps us focused. We will objective in 2003. The dividend yield not waiver.

is attractive, at over 5 percent, but the stock price has declined. As we work through the rate cases, our financial condition should improve. Ultimately, we want to deliver shareholder David E. Meador returns that stand out in our industry. SeniorVice President and Chief Financial Officer I111IR0190aw7D 1= =

DTE ENERGY COMPANY Management's Discussion and Analysis of Financial Condition and Results of Operations Overview by the MPSC, while alternative suppliers can charge market-based rates. This continued regulation has hindered Detroit Edison's DTE Energy isa diversified energy company with approximately ability to retain customers. Detroit Edison's results have been

$7billion in revenues in 2003 and approximately $21 billion in unfavorably impacted by the lack of recovery of lost margins and assets at December 31, 2003. We are the parent company of other costs associated with the electric Customer Choice program.

Detroit Edison and MichCon, regulated electric and gas utilities Under Michigan legislation, we are allowed to recover net stranded engaged primarily inthe business of providing electricity and costs associated with the electric Customer Choice program. To natural gas sales and distribution services throughout southeastern date, the MPSC has not fully implemented various provisions of Michigan. Additionally, we have numerous non-regulated Michigan's restructuring legislation. Specifically, the MPSC:

subsidiaries involved in energy-related businesses predominantly in the Midwest and eastern U.S.

has not finalized all the components for calculating net stranded costs; The majority of our earnings are derived from utility operations and

has created a process whereby net stranded costs would be the production of synthetic fuel, which qualifies for Section 29 tax recovered two years after the costs were actually incurred; credits. Earnings in 2003 were $521 million, or $3.09 per diluted

has not authorized timely recovery of any implementation costs share, down from 2002 earnings of $632 million, or $3.83 per diluted associated with the electric Customer Choice program; and share. Eamings from continuing operations in 2003 were $480 million,

has created artificial incentives to encourage participation in or $2.85 per diluted share, compared to 2002 earnings from continuing the electric Customer Choice program operations of $586 million, or $3.55 per diluted share. The 18%

decrease in income reflects significantly lower utility earnings, Inaddition, the MPSC has maintained regulated rates for certain partially offset by increased contributions from our non-regulated groups of customers that exceed the cost of service to those businesses. Our 2003 financial performance was primarily customers. This has resulted in high levels of participation inthe influenced by: electric Customer Choice program by those customers that have

Weather, including storms and power outages; the highest price relative to their cost of service. As a result, we

Lost revenues from electric Customer Choice penetration; -

continue to lose sales each year and are seeing an accelerating pace of migration towards the end of 2003. Lost margins and

The regulatory environment in Michigan and the need to electricity volumes associated with electric Customer Choice were increase utility rates; approximately $120 million and 7,281 gigawatthour (gWh) in 2003,

Higher operating costs; compared with $50 million and 3,510 gWh in 2002. InFebruary

The optimization of Section 29 tax credits; and 2004, the MPSC authorized an interim base rate increase that

Growth of non-regulated businesses recognized a revenue deficiency for lost Choice revenues, and eliminated transition credits and implemented a transition charge Weather- Earnings in our electric and gas utilities are seasonal for Choice customers. The interim order isexpected to reduce the and extremely sensitive to weather. Electric utility earnings are level of Choice sales volumes. Assuming no further changes to the dependent on hot summer weather while the gas utility's results current electric Customer Choice program, we expect to continue are driven by cold winter weather. We experienced both milder losing margins and volumes in 2004. Partially offsetting the summer and winter weather during 2003, which negatively impacted impact of lost margins in2003, we recorded regulatory assets of $68 sales demand. The lower demand reduced current year earnings million representing an estimate of stranded costs that we believe by $64 million compared to 2002, which was an above-normal are recoverable under Michigan legislation. Based on the MPSC's weather demand year. July 2003 order, we do not believe that any of the stranded costs in years prior to 2003 are recoverable. There are a number of Additionally, we occasionally experience various types of storms variables and estimates that impact the level of recoverable stranded that damage our electric distribution infrastructure resulting in costs, including weather, sales mix and wholesale prices. As a result, power outages. Our current year earnings were affected by several our estimate of stranded costs could increase or decrease. The catastrophic wind and ice storms, as well as by the August blackout. actual amount of stranded costs to be recovered will ultimately Restoration and other costs associated with these power outages be determined by the MPSC.

lowered 2003 earnings by an additional $31 million compared to 2002.

Detroit Edison addressed numerous issues with the electric Electric Customer Choice Program - The electric Customer Choice Customer Choice program, including stranded costs, in its June program as originally structured in Michigan anticipated an eventual 2003 rate filing and is also pursuing a legislative solution. Under transition to atotally deregulated and competitive environment the legislative solution, we are proposing to limit Customer Choice where customers would be charged market-based rates for their program participation to customers whose electric demand is electricity. However, Detroit Edison's rates continue to be regulated 1 MW or greater. The continued delay in addressing the structural III '~

problems of the electric Customer Choice program and the timely Synthetic Fuel Operations- We operate nine synthetic fuel production and full recovery of stranded costs, unfavorably impacts earnings plants at eight locations. Interests in two of the nine plants were and cash flow. See Note 4 for a further discussion of the electric sold in 2002, interests in three other plants were sold in November Customer Choice program and the MPSC interim rate order. 2003, and additional interests were sold inJanuary 2004 in two of the plants sold in 2003. We continue to wholly own the remaining Electric and Gas Rate Plans- In2000, Michigan legislation froze four plants, but intend to sell interests in all such plants in 2004.

electric rates for all residential, commercial and industrial customers Synfuel facilities chemically change coal, including waste and through 2003. The legislation also prevented rate increases or marginal coal, into a synthetic fuel as determined under applicable capped rates for residential customers through 2005, and for small IRS rules. Section 29 of the Intemal Revenue Code provides tax commercial and industrial customers through 2004. The rate credits for the production and sale of solid synthetic fuel produced freeze and caps apply to base rates as well as rates designed to from coal. Inaddition to meeting various qualifying conditions, recover fuel and purchased power costs. Historically, these costs a taxpayer must have sufficient taxable income to earn the have been a pass-through under the power supply cost recovery Section 29 credits.

(PSCR) mechanism.

Our 2003 earnings were unfavorably affected by our inability to InJune 2003, Detroit Edison filed an application with the MPSC sell interests in synfuel plants until late 2003. The IRS suspended for: 1)an increase in retail electric rates of $427 million annually, the issuance of private letter rulings (PLRs) relating to synthetic 2)the resumption of the PSCR mechanism, and 3)the recovery of fuel projects in May 2003, pending its review of issues concerning net stranded and other costs as permitted under Michigan legislation. chemical change, which isthe basis for earning Section 29 tax Detroit Edison received an interim order inthis rate case authorizing credits. As a result of the IRS suspension, we were unable to an increase in rates of $248 million annually. As a result of rate complete the pending sale of interests in our synfuel projects. In caps and other factors, the interim rate increase isonly designed addition, we experienced lower taxable earnings due to milder to increase revenues by $71 million in 2004 (Note 4). A final order weather and continued cost and margin pressures. The temporary is expected inthe third quarter of 2004. The rate increase iseffective delay in selling interests inthe synfuel projects, coupled with the for each customer class upon the expiration of the applicable rate lower taxable earnings, resulted in our capacity to generate more I

cap period. The rate request isdesigned to more accurately reflect, credits than we could utilize. These factors caused us to reduce among other things, significantly higher cost of service levels that our synthetic fuel production by approximately one-half inJune Detroit Edison has experienced over the past few years. 2003 to optimize the tax credits generated from these facilities. We began implementing a series of initiatives, including the monetization The recovery of net stranded costs, electric Customer Choice of in-the-money gas swap derivative contracts, to improve cash implementation costs and other costs incurred as a result of changes flow and increase taxable income thereby allowing us to more fully in taxes, laws and governmental actions are covered under Michigan utilize our Section 29 tax credits.

legislation. However, the MPSC has not approved a final mechanism to recover such costs, and this has negatively affected our cash flow. InOctober 2003, the IRS concluded its assessment of the chemical As part of its rate filing, Detroit Edison has requested authorization change process involved in synfuel production and resumed issuing to implement a 5-year surcharge to recover these costs. The MPSC PLRs. The IRS determined that the test procedures and results deferred addressing this item until afinal rate order is issued. used by taxpayers were scientifically valid if the procedures were applied in a consistent and unbiased manner. The conclusion of InSeptember 2003, MichCon filed an application with the MPSC the IRS assessment allowed us to complete the sale of interests in for an increase in service and distribution charges for its gas sales additional facilities and increase synfuel production levels for the and transportation customers totaling $194 million annually. The balance of 2003.

rate increase would be MichCon's first since 1992, and isdesigned to recover significantly higher operating costs. MichCon expects Non-regulated Growth- During 2003, we continued to experience an interim order in this case in mid-2004, with afinal order by growth in our non-regulated businesses with income reaching January 2005. $199 million compared to $168 million in 2002. The significant improvement reflects increased contributions from our Energy Operating Costs- During 2003, we experienced double-digit Services segment due to higher synfuel production, partially offset increases in regulated operation and maintenance costs. The by the impact of certain coke battery-related Section 29 tax credits increases were driven by higher costs associated with pension expiring in 2002. Additionally, non-regulated growth in 2003 is and health care benefits, uncollectible accounts receivable and attributable to increased margins in our Energy Marketing & Trading customer service initiatives. To address this issue of rising costs, segment. We also realized gains in 2003 from the sale of our we implemented several cost savings initiatives that partially 16% interest in the Portland Natural Gas Transmission System, offset these increases. Some of the initiatives were structural an interstate pipeline company, and the settlement of atolling innature, whereas others were temporary. Examples of these contract at one of our merchant generating facilities.

initiatives included ahiring freeze, a pause on discretionary spending and overtime restrictions. Additionally, we reduced employee Although DTE Energy's overall earnings were down 18% in 2003, compensation costs, property and other taxes as well as interest our cash from operations totaling $950 million was comparable to costs through debt refinancings. the prior year despite a $222 million cash contribution to our pension plan. Operating cash flow reflects our successful initiative in 2003 EI, NW

'II

to conserve cash, including better working capital management. This non-regulated operations. The balance of our business consists of initiative coupled with $233 million in lower capital expenditures and Corporate & Other. Based on this structure, we set strategic goals, over $750 million from selling non-strategic and other assets, resulted allocate resources and evaluate performance. This results inthe in a lower debt to total capital ratio and a healthier balance sheet. following reportable segments.

Outlook- We are facing many challenges in2004 to maintain (inMillions, exceptper share data) 2003 2002 2001 earnings and cash flow levels, while protecting a strong balance Net Income (Loss) sheet. Our financial performance over the short term will be Energy Resources dependent on preserving healthy electric and gas utilities, monetizing Regulated - Power Generation S 235 $ 241 $ 139 our synthetic fuel projects and continuing to grow our non-regulated Non-regulated businesses in a prudent manner. Energy Services 199 182 115 Energy Marketing & Trading 45 25 44 Remedying the structural issues of the electric Customer Choice Other (2) 7 6 program in Michigan is a key priority for the organization. These Total Non-regulated 242 214 165 issues must be corrected to prevent the continued migration of 477 455 304 customers to the Choice program based on false market signals. Energy Distribution The potential implications to remaining customers over the longer, Regulated - Power Distribution 17 111 97 term could be significantly higher electricity rates. Non-regulated (15) (16) (10)

The timing and ultimate amount of final rate relief granted inthe 2 95 87 current electric and gas rate cases will affect customer service Energy Gas Regulated - Gas Distribution 29 66 (38) levels and our financial performance. Cash flow and earnings Non-regulated 29 26 11 from our utilities will remain under pressure until the regulatory uncertainties are resolved. However, we remain focused on good 58 92 (27) cash management and a healthy balance sheet. Corporate & Other (57) (56) (55)

Income from Continuing Operations We are aggressively pursuing the sales of interests in all of our Regulated 281 418 198 remaining synthetic fuel projects in 2004. These sales, in addition Non-regulated (1) 199 168 111 to previously completed sales, are expected to provide a $200 million 480 586 309 to $300 million boost to our cash flow in 2004. The availability Discontinued Operations 68 46 20 of qualified buyers and the timing of these sales will impact Cumulative Effect of Accounting this financial outcome. Inaddition, we are continuing to grow Changes (27) - 3 our non-regulated businesses in areas such as waste coal Net Income $ 521 $ 632 S 332 technologies, coal bed methane production and on-site energy project development. Due to the regulatory uncertainties over Diluted Earnings Per Share the short term, we remain disciplined and conservative in our Regulated $ 1.67 $ 2.53 $ 1.29 pursuit of incremental growth investments. Non-regulated 11) 1.18 1.02 .72 Income from Continuing Operations Z85 3.55 2.01 Discontinued Operations .40 .28 .13 Results of Operations Cumulative Effect of Accounting We had income of $521 million in 2003, or $3.09 per diluted share, Changes (.16) - .02 compared to income of $632 million, or $3.83 per diluted share in Net Income $ 3.09 $ 3.83 $ 2.16 2002 and income of $332 million, or $2.16 per diluted share in (1)Includes Corporate &Other.

2001. The comparability of earnings was impacted by the sale of our transmission business, International Transmission Company (ITC), and the adoption of new accounting rules as subsequently ENERGY RESOURCES discussed. Upon selling ITC in February 2003, we classified this Power Generation business as a discontinued operation. Excluding discontinued operations and the cumulative effect of accounting changes, our The power generation plants of Detroit Edison comprise our earnings from continuing operations in 2003 were $480 million, or regulated power generation business. Detroit Edison's numerous

$2.85 per diluted share, compared to earnings of $586 million, or fossil plants, its hydroelectric pumped storage plant and its

$3.55 per diluted share in 2002 and earnings of $309 million, or nuclear plant generate electricity. The generated electricity,

$2.01 per diluted share in 2001. The following sections provide a supplemented with purchased power, issold principally throughout detailed discussion of our segments, operating performance and Michigan and the Midwest to residential, commercial, industrial future outlook. and wholesale customers.

Segment Performance & Outlook-We operate our businesses through three strategic business units (Energy Resources, Energy Distribution and Energy Gas). Each business unit has regulated and II 04Y.M 'i

(inMillions) 2003 2002 2001 revenues from these retail customers were affected by customers Operating Revenues $ 2448 $ 2,711 S 2,788 switching to alternative suppliers under the electric Customer Fuel and Purchased Power (920) (1,048) (1,231) Choice program. Revenues from wholesale customers were Gross Margin 1,528 1,663 1,557 reduced, reflecting lower power prices. Partially offsetting these Operation and Maintenance (528) (626) (571) revenue reductions was the impact of weather, resulting in a 10%

Depreciation and Amortization (224) (331) (385) increase in cooling demand during 2002.

Taxes OtherThan Income 1157) (156) (148) (inThousands of MMh ) 2003 2002 2001 Merger and Restructuring Charges Power Generated (Note 3) - - (72) and Purchased Operating Income 519 550 381 Power Plant Generation Other Income and (Deductions) (149) (189) (184) Fossil Income Tax Provision (135) 1120) (58) Coal 37,408 71% 37,381 64% 38,424 69%

NetIncome S 235 $ 241 $ 139 Natural Gas & Other 644 1 1,636 3 1,287 2 Operating Income as a Nuclear (Fermi 2) 8,114 16 9,301 16 8,555 16 Percent of Operating Revenues 21% 20% 14% 46,166 88 48,318 83 48,266 87 Purchased Power 6354 12 9,807 17 7,482 13 Factors impacting income: Power Generation earnings decreased System Output 52520 100% 58,125 100 % 55,748 100%

$6million in 2003 and increased $102 million in 2002, compared Average Unit to the prior year. As subsequently discussed, these results Cost (S/MWh) primarily reflect changes in gross margins, increased operation and Generation (1) $1Z89 $ 12.53 $ 12.31 maintenance expenses and the recording of higher regulatory Purchased Power (2) S 41.73 $ 39.16 $ 78.24 deferrals, which lowered depreciation and amortization expenses. Overall Average Unit Cost S 1638 $ 17.02 S 21.15 (1)Represents fuel costs associated with power plants.

Merger and restructuring charges associated with the 2001 MCN (2)Includes amounts associated with hedging activities.

Energy acquisition also impacted the comparability of results. These Operation and maintenance expense increased $2million in 2003 charges represent costs associated with systems integration, and $55 million in2002. Operation and maintenance expenses in 2003 relocation, legal, accounting and consulting services, as well as were affected by $5million in costs associated with the August 2003 costs associated with awork force reduction plan. The plan blackout (Note 4)and a $69 million increase in employee pension and included early retirement incentives and voluntary separation health care benefit costs, due to recent financial market performance, agreements for employees inoverlapping corporate support areas. lower discount rates and increased health care trend rates. Partially offsetting these increases were benefits from the DTE Operating Gross margins in 2003 declined $135 million due primarily to System, our company-wide initiative to pursue cost efficiencies as decreased cooling demand resulting from mild summer weather, well as enhance operating performance. The DTE Operating lost margins from customers choosing to purchase power from System involves the application of tools and operating practices, alternative suppliers under the electric Customer Choice program which have resulted in inventory reductions and improvements in and lost margins from the August 2003 blackout. Weather in 2003 technology systems, among other enhancements. Operation and was 38% milder than 2002 resulting in lost margins of $114 million. maintenance expenses in 2003 also benefited from $23 million in Detroit Edison lost 16% of retail sales in2003 and 6%of such sales of emissions credits and lower employee incentive costs.

sales in2002 as'a result of customers choosing to purchase power from alternative suppliers under the electric Customer Choice Operation and maintenance expenses in 2002 reflect $18 million in program. We estimate that we lost $120 million of margins in higher employee pension and health care benefit costs and $43 2003 under the electric Customer Choice program, an increase of million inexpenses associated with maintaining our generation fleet.

$70 million over 2002. Lost Choice margins that we believe are The 2002 increase also includes a $5million increase inallocations recoverable under Michigan legislation are recorded as regulatory for corporate support services, as well as $11. million to fund the assets and therefore reduced depreciation and amortization low income and energy efficiency fund. The funding of the low expense as subsequently discussed. Gross margins benefited from income and energy efficiency program was required under a $.64 per MWh (4%) decline in fuel and purchased power costs Michigan legislation and is recovered in current sales rates.

reflecting the use of a more favorable power supply mix. The favorable mix isdue to lower purchases, which is driven by lost Depreciation and amortization expense decreased $107 million sales under the electric Customer Choice program. in 2003 and $54 million in 2002. The decrease in depreciation and amortization expense isattributable to the income effect of Gross margins in 2002 improved $106 million due primarily to recording regulatory assets totaling $126 million in 2003 and significantly lower fuel and purchased power costs, partially offset $41 million in 2002 representing the deferral of net stranded and by reduced operating revenues. The reduction in fuel and purchased other costs we believe are recoverable under Public Act 141. The power costs was driven by a$39.08 per MWh (50%) reduction in decline in 2002 also reflects the extension of the amortization average purchased power prices from 2001 levels. The decline in period from seven years to 14 years for certain regulatory assets operating revenues is attributable to commercial, industrial and that were securitized in 2001. See Note 4 - Regulatory Matters.

wholesale customers. Commercial and industrial revenues were Partially offsetting these declines was increased depreciation lower due to a full year's impact of a 5%legislatively mandated associated with generation-related capital expenditures.

rate reduction for customers that began in April 2001. Additionally,

Other income and deductions declined $40 million in 2003 and Factors impacting income: Energy Services earnings increased $17 increased $5million in 2002. The reduction in 2003 isattributable million in 2003 and $67 million in 2002, compared to the prior year.

to lower interest expense and increased interest income. Interest As subsequently discussed, these results primarily reflect increases expense reflects lower borrowing levels and rates, and interest in synfuel production, varying levels of Section 29 tax credits, a income includes the accrual of carrying charges on environmental- one-time contract gain and awrite-off of an uncollectible account.

related regulatory assets.

Operating revenues increased $284 million in 2003 and $198 million Outlook- Future operating results are expected to vary as a result in 2002 reflecting higher synfuel production due to a greater number of external factors such as regulatory proceedings, new legislation, of operating synfuel plants. All nine of our synfuel plants were changes in market prices of power, changes ineconomic conditions operational throughout 2003, whereas only five were operational and the levels of customer participation in the electric Customer throughout 2002 and only two in2001. As discussed in Note 13, Choice program. the growth in synfuel revenues was tempered by our decision to reduce synfuel production by approximately one-half inJune 2003.

As previously discussed, we expect to continue losing retail sales Also impacting the 2003 comparison was reduced generation and margins in future years under the electric Customer Choice revenue due to the settlement of atolling contract at one of our program until the inequities associated with this program are generating facilities.

addressed. We will accrue as regulatory assets our unrecovered generation-related fixed costs due to electric Customer Choice that (Dollars inMillions) 2003 2002 2001 we believe are recoverable under Michigan legislation. We have Coal-Based Fuels Statistics addressed the issue of stranded costs in our June 2003 electric rate Synfuel Plants:

filing and are also pursuing a legislative solution. Additionally, we Operational at End of Year 9 9 5 requested an increase in retail electric rates of $427 million annually Tax Credits Generated (1) S 227.7 S 180.2 $ 64.1 to recover higher operating costs and the resumption of the PSCR Coke Battery Plants:

mechanism. InFebruary 2004, the MPSC authorized an interim Operational at End of Year 3 3 3 base rate increase of $248 million annually. The actual timing and Tax Credits Generated (1) S 2.5 $ 57.4 S 88.6 level of recovering stranded and operating costs will ultimately be determined by the MPSC or legislation. We cannot predict the (1)DTE Energy's portion of total tax credits generated outcome of these matters. See Note 4- Regulatory Matters. Operation and maintenance expense increased $258 million in 2003 and $308 million in 2002, reflecting costs associated with the higher Energy Services levels of synfuel production. Operating expenses associated with synfuel projects exceed operating revenues and therefore generate Energy Services is comprised of Coal-Based Fuels, On-Site Energy operating losses, which are more than offset by the resulting Projects and Merchant Generation. Coal-Based Fuels operations Section 29 tax credits. Operation and maintenance expense in 2003 include producing synthetic fuel from nine synfuel plants and also includes a$10 million net of tax write-off for an uncollectible producing coke from three coke battery plants. Both processes receivable associated with a large customer bankruptcy. Partially generate tax credits under Section 29 of the Internal Revenue Code.

offsetting these increases was a one-time $19 million net of tax On-Site Energy Projects include pulverized coal injection, power gain from the settlement of the tolling contract.

generation, steam production, chilled water production, wastewater treatment and compressed air supply. Merchant Generation owns Other income and deductions increased $16 million in 2003 and and operates four gas-fired peaking electric generating plants and $87 million in 2002. The increases reflect our minority partners' develops and acquires gas and coal-fired generation. share of operating losses associated with synfuel operations.

(inMillions) 2003 2002 2001 The sale of interests in our synfuel facilities during 2002 and 2003 Operating Revenues resulted in our minority partners being allocated a larger percentage Coal-Based Fuels S 850 $ 559 $ 365 of such losses.

On-Site Energy Projects 70 63 53 Merchant Generation 9 23 29 Income tax benefits decreased $19 million in 2003 and increased 929 645 447 $95 million in 2002. Income tax variations reflect changes in taxable earnings and the level of Section 29 tax credits from our Operation and Maintenance (966) (708) (400) synfuel and coke battery facilities. Tax credits from our synfuel Depreciation, Depletion andAmortization (84) (81) (85) operations increased in each of the last two years due to higher Taxes Other Than Income (18) (15) (6) synfuel production. Tax credits from our coke battery production Operating Loss (139) (159) (44) reflect the expiration of such credits at two of our three plants in Other Income and (Deductions) 89 73 (14) 2002. Additionally, tax credits were impacted by our interest in Income Taxes one of the coke battery projects being reduced from 95% to 5%in Benefit 19 30 20 2002, consistent with the original purchase and sale agreement.

Section 29 Tax Credits 230 238 153 249 268 173 Outlook- A significant portion of Energy Services' earnings consist Net Income $ 199 $ 182 S 115 of Section 29 tax credits. Synfuel-related tax credits expire in 2007. Tax credits for two of our three coke batteries expired at the end of 2002, and the third expires in 2007. We are aggressively III I~m I

pursuing opportunities to sell interests in all of our synfuel plants (inMillions) 2003 2002 2001 in 2004. The level of tax credits generated infuture periods will be DTE Energy Trading affected by the timing and number of synfuel projects sold. When we Margins - gains (losses) sell an interest in a synfuel facility, we recognize the gain from such Realized (1): $ 82 $ 38 $ 33 sale under the installment method of accounting. Gain recognition Unrealized (2) (9). 13 (6) isdependent on the synfuel production qualifying for Section 29 73 51 27 tax credits. Insubstance, we are receiving installment gains and Operating and other costs (28) (29) 114) reduced operating losses in exchange for tax credits. Sales of Income taxes (13) (8) (5) interests in synfuel projects allow us to accelerate cash flow while Net income S 32 $ 14 S 8 maintaining a stable income base. CoEnergy Margins - gains (losses)

There isa bill currently before the United States Congress that Realized (1) S 168 $ 32 $ (6) includes provisions extending or reinstating tax credits for various Unrealized (2) (135) (62) 108 types of energy facilities and processes, including coke batteries, Unrealized-gas in inventory (3) - 74 (28)

Antrim shale gas, coal bed methane, refined coal and landfill gas. 33 44 74 We are unable to predict the outcome of the legislative process. Operating and other costs (13) (27) (19)

Income taxes (7) (6) (19)

Energy Services will continue leveraging its extensive energy-related Netincome $ 13 $ 11 $ 36 operating experience and project management capability to Total Energy Marketing & Trading develop and grow the on-site energy business. We continue to Net Income $ 45 $ 25 $ 44 explore growth opportunities that will not require significant initial (1)Realized margins include the settlement of all derivative and non-derivative capital investment. We are currently negotiating an on-site energy contracts, as well as the amortization of deferred assets and liabilities.

business arrangement with a major manufacturer inthe Midwest. (21Unrealized margins include mark-to-market gains and losses on derivative contracts, net of gains and losses reclassified to realized. See 'Fair Value of Power prices over the past few years have been low due, in part, to Contracts' section that follows. :

the current excess capacity inthe generation industry. Additionally, (3)Unrealized - gas in inventory margins represent gains and losses associat-the generation tolling agreement that was settled in2003 was at ed with fair value accounting in2002 and 2001. CoEnergy changed its method of accounting for inventory inJanuary 2003 (Note 2).

above market rates. As a result of these factors, we expect lower revenues and earnings from our merchant generation business in2004. CoEnergy's earnings in 2003 and 2002 were driven by varying levels of operating costs and margins' Operating costs reflect the Energy Marketing &Trading scale-back of certain retail gas marketing operations in 2002 as Energy Marketing & Trading consists of the electric and gas well as lower allocations for corporate support services in 2003.

marketing and trading operations of DTE Energy Trading and CoEnergy. OTE Energy Trading focuses on physical power marketing Variations in margins reflect: 1)the settling or monetizing of certain and structured transactions, as well as the enhancement of returns in-the-money derivative contracts in 2003, 2)a change in the method from DTE Energy's power plants. CoEnergy focuses on physical gas of accounting for our gas in inventory in January 2003, and 3) marketing and the optimization of DTE Energy's owned and contracted volatility related to the accounting for our production-related gas natural gas pipelines and gas storage capacity. To this end, both supply contracts in 2001.

companies enter into derivative financial instruments as part of their strategies, including forwards, futures, swaps and option contracts. We monetized certain in-the-money derivative contracts in 2003 The derivative financial instruments are accounted for under the mark while simultaneously entering into replacement at-the-market to market method, which results in earnings recognition of unrealized contracts with various counterparties. The monetizations were gains and losses from changes in the fair value of the derivatives. completed in conjunction with implementing a series of initiatives to improve cash flow as well as our ability to fully utilize Section Factors impacting income Energy Marketing & Trading's earnings 29 tax credits (Note 13). The monetizations had the impact of increased $20 million in 2003, of which $18 million was attributable reducing unrealized gains and increasing realized gains by to DTE Energy Trading and $2million to CoEnergy. Earnings for 2002 approximately $136 million, with no significant impact on earnings.

decreased $19 million, consisting of a $6million improvement at DTE Energy Trading, which was more than offset by a $25 million As previously discussed, our derivative financial instruments are reduction at CoEnergy. accounted for under the mark to market method, including those derivatives that hedge our price risk exposure associated with gas DTE Energy Trading's earnings improvement in 2003 and 2002 was in inventory. Through December 2002, our physical gas in inventory due mainly to margins associated with short-term physical trading was marked to the current spot price under fair value accounting and origination activities. The improvement was partially offset by rules. Accordingly, mark to market accounting for derivatives, coupled reduced proprietary trading profits. Proprietary trading represents with fair value accounting for gas in inventory, minimized earnings derivative activity transacted with the intent of capturing profits on mismatches. To comply with new accounting requirements resulting forward price movements. from the rescission of Emerging Issues Task Force (EITF) Issue No.

98-10, 'Accounting for Contracts Involved in Energy Trading and Risk ManagementActivities," we changed to the average cost method

, i I

for our gas inventories, effective January 2003 (Note 2). As a result, This results in gains and losses that are recognized indifferent CoEnergy experienced earnings volatility as it recorded unrealized interim periods, but even out by the end of the storage cycle.

gains in 2002 and unrealized losses in 2001 from fair valuing its inventory, whereas no such gains or losses were recorded in 2003. InFebruary 2004, we terminated a long-term gas exchange agreement and modified our future purchase commitments under a related The comparability of CoEnergy's results was also affected by using transportation agreement with an interstate pipeline company, different market prices for fair valuing its derivatives and fair valuing effective March 31, 2004. The agreements were at rates that its gas in inventory, before the accounting change. Derivatives were not reflective of current market conditions and had been fair are marked to market against the forward curve, whereas gas in valued under generally accepted accounting principles. In 2002, inventory was marked to the current spot price. The difference in the fair value of the transportation agreement was frozen when it accounting for derivatives and gas in storage resulted inearnings no longer met the definition of a derivative as a result of FERC volatility in 2002 and 2001 when price changes inthe spot month Order 637. The fair value amounts were being amortized to did not correspond with those inthe forward market. Gas in storage income over the life of the related agreements, representing a in December 2002 was priced at a spot market rate of $5.10 Mcf, net liability of approximately $75 million as of December 31, 2003.

compared to $2.77 per Mcf in December 2001 and a May 31, 2001, We are currently negotiating new agreements with the interstate acquisition date rate of $4.10 per Mcf. Significantly smaller changes pipeline company. We will record an appropriate adjustment to the inforward prices occurred during these same periods. As a result, liability after all related agreements have been finalized.

the mark-to-market gains and losses on gas inventory were only partially offset by mark-to-market losses and gains on the storage- Non-regulated - Other related derivatives.

Our other non-regulated businesses are comprised of our Coal CoEnergy receives gas produced from DTE Energy's Gas Production Services and Biomass units. Coal Services provides fuel, transportation operations, which is used to meet its commitments under long-term and equipment management services. We specialize in minimizing contracts with cogeneration customers. The gas produced does energy production costs and maximizing reliability of supply for not qualify for mark-to-market accounting. CoEnergy recorded a energy-intensive customers. Additionally, we participate in coal gain in2001 totaling approximately $50 million, net of taxes, trading and coal-to-power tolling transactions as well as sales of primarily attributable to marking to market sales contracts with excess emissions credits. Coal Services has formed a subsidiary, power generation customers without recording an offsetting loss DTE PepTec Inc., that uses proprietary technology to produce high from marking to market the production-related gas supply. In quality coal products from fine coal slurries that are typically December 2001, CoEnergy entered into hedge transactions that discarded from coal mining operations. Biomass develops, owns substantially mitigate the earnings volatility related to the gas and operates landfill recovery systems in the U.S. Gas produced contracts with power generation customers. from these landfill sites qualifies for Section 29 tax credits.

Outlook- Energy Marketing & Trading will seek to manage its Factors impacting incomr. Earnings declined $9million in 2003 and business in a manner consistent with and complementary to increased $1million in 2002. The 2003 decline reflects reduced the growth of our other business segments. Gas storage and marketing and tolling income as well as an increase in operating transportation capacity enhances our ability to provide reliable costs associated with ramping up the DTE PepTec business. Our and custom-tailored bundled services to large-volume end users first waste coal facility inOhio became operational in late-2003.

and utilities. This capacity, coupled with the synergies from DTE (Dollars inMillions) 2003 2002 2001 Energy's other businesses, positions the segment to add value. Coal Services Tons of coal shipped (inmillions) 32.0 28.5 23.5 Significant portions of the Energy Marketing & Trading portfolio are economically hedged, and include financial instruments, gas Biomass inventory, as well as owned and contracted natural gas pipelines Gas Produced (inBcf) 26.8 27.5 24.2 and storage assets. These financial instruments are deemed derivatives whereas the gas inventory, pipelines and storage Tax Credits Generated (1) $ 10.5 $ 12.9 $ 11.9 assets are not considered derivatives for accounting purposes. (11 DTE Energy's portion of total tax credits generated As a result, Energy Marketing & Trading will experience earnings volatility as derivatives are marked to market without revaluing the Outlook- We expect to continue to grow our Coal Services and underlying non-derivative contracts and assets. Biomass units. We believe a substantial market exists for the use of DTE PepTec Inc. technology and plan to aggressively pursue A significant portion of the earnings volatility inthis segment is expansion opportunities. We expect to open 3 to 5 operating sites associated with the natural gas storage cycle, which runs from in 2004. Biomass currently has 31 operating sites and other projects June to March. Injections of gas into inventory takes place in the under development. Section 29 tax credits related to Biomass summer and gas iswithdrawn in the winter. DTE Energy's policy is operations expire in 2007.

to hedge the price risk of all purchases for storage with sales in the "over the counter" and futures markets, eliminating the price risk for the storage business. As previously discussed, current accounting rules do allow for the marking to market of forward sales, but do not allow for the marking to market of the related gas inventory.

,, ' , 'I

ENERGY DISTRIBUTION blackout, affecting all 2.1 million of our customers. This compares with $49 million in costs in2002 related to two catastrophic storms, Power Distribution as well as heat-related maintenance expenses due to prolonged Power Distribution operations include the electric distribution services periods of above normal summer temperatures and the related of Detroit Edison. Power Distribution distributes electricity generated stress placed on our distribution system.

and purchased by Energy Resources and alternative electric suppliers to Detroit Edison's 2.1 million customers. Employee pension and health care benefit costs increased $26 million in 2003 and $12 million in 2002 due to recent financial market (inMillions) 2003 2002 2001 performance, lower discount rates and increased health care trend Operating Revenues $ 1,247 $ 1,343 $ 1,256 rates. Uncollectible accounts expense increased $17 million in Fuel and Purchased Power (19) (26) (10) 2003 and decreased $1million in 2002 reflecting higher past due Operation and Maintenance (724) (649) (511) amounts attributable to current economic conditions. Additionally, Depreciation, Depletion and Amortization (249) (246) (246) results for 2003 also reflect costs associated with customer service Taxes Other Than Income (100) (117) (120) initiatives and a net of tax loss of $14 million on the sale of our Merger and Restructuring Charges - - (114) non-strategic steam heating business (Note 3). Partially offsetting Operating Income _ 155 305 255 these increases were benefits from the DTE Operating System, as Other Income and (Deductions) (128) (136) (132) previously discussed, and lower employee incentive costs.

Income Tax Provision (10) (58) (26)

Netincome S 17 $ 111 $ 97 Taxes otherthan income decreased $17 million in2003 and $3million Operating Income as a Percent in 2002. The decline in2003 isdue to lower Michigan Single Business of Operating Revenues 12% 23% 20% Taxes, reflecting reduced taxable earnings, and lower property taxes.

Outlook- Operating results are expected to vary as a result of Factors impacting income: Power Distribution earnings decreased external factors such as weather, changes in economic conditions

$94 million during 2003 and increased $14 million in2002, compared and the severity and frequency of storms. Economic conditions to the prior year. As subsequently discussed, these results primarily and prior billing issues have resulted in an increase in past due reflect changes in operating revenues and increased operation and receivables. We believe our allowance for doubtful accounts is maintenance expenses. Merger and restructuring charges based on reasonable estimates. However, failure to make continued associated with the 2001 MCN Energy acquisition also impacted the comparability of results. progress in collecting our past due receivables would unfavorably affect operating results. As a result, we have organized a focused Operating revenues declined $96 million in 2003 primarily due to effort to address the credit and collection issues.

mild summer weather and the impact of slower economic conditions affecting commercial and industrial sales. Operating revenues We experienced numerous catastrophic storms over the past few increased $87 million in 2002 reflecting higher residential sales years. The effect of the storms on annual earnings ranged up to attributable to greater cooling demand. $70 million and was partially offset by storm insurance. We were unable to obtain storm insurance at economical rates in 2004 and Below are volumes associated with the regulated power as a result, we do not anticipate having insurance coverage at levels distribution business: that would significantly offset unplanned expenses from ice storms, tornadoes, or high winds that damage our distribution infrastructure.

(inThousands of MW/h) 2003 2002 2001 Electric Deliveries As previously mentioned, Detroit Edison filed a rate case in June Residential 15,074 15,958 14,503 2003 to address future operating costs and other issues. Detroit Commercial 15,942 18,395 18,777 Edison received an interim order inthis rate case in February 2004.

Industrial d12254 13,590 14,430 See Note 4- Regulatory Matters.

Wholesale 2241 2,249 2,159 45,511 50,192 49,869 Non-Regulated Electric Choice 7,281 3,510 1,268 Non-regulated Energy Distribution operations consist of DTE Energy Total Electric Deliveries 52792 53,702 51,137 Technologies which markets and distributes distributed generation products, provides application engineering, and monitors and Operation and maintenance expense increased $75 million in2003 manages generation system operations.

and $138 million in 2002 reflecting higher costs associated with weather-related power outages, employee benefits, uncollectible Factors impacting income, Non-regulated losses decreased $1million accounts receivables, allocations for corporate support services, in 2003 and increased $6million in 2002. The slight improvement and customer service initiatives to improve customer satisfaction. in 2003 isdue primarily to increased sales and cost reductions.

Restoration costs associated with three catastrophic storms in 2003 and the August 2003 blackout totaled $76 million. We experienced Outlook- Although installed capacity for DTE Energy Technologies an April ice storm, resulting in more than 400,000 customers losing is increasing, the growth inthis business is below our expectations.

power, a July windstorm, affecting over 190,000 customers, a Accordingly, we have taken actions to reduce our expenses and November windstorm, affecting 160,000 customers, and the August streamline our operations, including exiting from some non-strategic III I' 'i

business lines and activities. DTE Energy Technologies expects to Income taxes in 2003 were impacted by lower earnings and continue participating in the emerging distributed generation market. favorably affected by an increase in the amortization of tax benefits previously deferred in accordance with MPSC regulations.

p I -1 ENERGY GAS Outlook- Operating results are expected to vary as a result of

ae nietrihiitinn external factors such as regulatory proceedings, weather and changes in economic conditions. Higher gas prices, current economic conditions Gas Distribution operations include gas distribution services- i and prior billing issues have resulted in an increase in past due primarily provided by MichCon, our gas utility that purchases, receivables. We believe our allowance for doubtful accounts is stores, distributes and sells natural gas to 1.2 million residential, based on reasonable estimates. However, failure to make continued commercial and industrial customers located throughout Michigan. progress in collecting our past due receivables would unfavorably affect operating results. As previously discussed, we are focused (inMillions) 2003 2002- 2001*

on addressing the credit and collection issues.

Operating Revenues S 1,498 $ 1,369 $ 615 Fuel and Purchased Power (909) (774) (304) The MPSC issued several orders that continue the gas Customer Gross Margins 589 595 - 311 Choice program on a permanent basis. Since MichCon continues to Operation and Maintenance 1371) (297) -1194) transport and deliver the gas to the participating customer premises Depreciation, Depletion and Amortization (101) (104) 161) at prices comparable to margins earned on gas sales, customers Taxes OtherThan Income (52) (51) (24) switching to other suppliers have little impact on MichCon's earnings.

Merger and Restructuring Charges - - (81) As of December 2003, approximately 129,000 customers were Operating Income (Loss) 65 143 (49) participating in the gas Customer Choice program, compared with Other Income and (Deductions) (36) (41) (38) approximately 190,000 customers as of December 2002.

Income Tax Benefit (Provision) - (36) 49 Net Income (Loss) S 29 $ 66 $ (38) As a result of the continued increase in operating costs, MichCon Operating Income as a - filed a rate case in September 2003 to increase rates by $194 million Percentof Operating Revenues 4% 10% n/m% annually to address future operating costs and other issues. See Note 4 - Regulatory Matters.

Reflects the operations of MichCon from the May 31,2001 acquisition date.

n/m -notmeaningful Non-regulated Factors impacting income, Gas Distribution's earnings declined $37 Non-regulated operations include the Gas Production business and million in 2003 and increased $104 million in 2002, compared to the Gas Storage, Pipelines & Processing business. Our Gas Production the prior year. As subsequently discussed, results in2003 primarily business produces gas from proven reserves in northern Michigan reflect a decline in gross margins and increased operation and and sells the gas to the Energy Marketing & Trading segment. Gas maintenance expenses. The significant improvement in 2002 Storage, Pipelines & Processing has a partnership interest in an reflects a full year of operations of MichCon, which was acquired - interstate transmission pipeline, seven carbon dioxide processing in conjunction with the MCN Energy merger in May 2001. In facilities and a natural gas storage field, as well as lease rights to contrast to 2001, the 2002 results include the January through another natural gas storage field. The assets of these businesses April period when demand for natural gas isat its highest. Merger are well integrated with other DTE Energy entities.

and restructuring charges associated with the merger also impacted the comparability. The pro-forma impact of the MCN Energy acquisition Factors impacting income, Earnings increased $3million in 2003 on DTE Energy isdiscussed in Note 3- Acquisitions and Dispositions. and $15 million in 2002. The 2003 earnings improvement primarily reflects the gain from the sale of our 16% pipeline interest in the Gross marginsdeclined $6million in2003 reflecting a $26.5 million Portland Natural Gas Transmission System. The 2002 results reflect reserve for the potential disallowance in gas costs pursuant to a afull year of operations of the our non-regulated gas businesses March 2003 MPSC order in MichCon's 2002 GCR plan case (Note 4). that were acquired inconjunction with the MCN Energy acquisition The impact of the reserve was significantly offset by increased in May 2001.

sales due to colder winter weather in early 2003.

Outlook- We expect to further develop our gas production properties Operation andmaintenance expense increased $74 million in in northern Michigan and our pipelines, processing and storage 2003 reflecting higher costs associated with employee benefits, assets to support other DTE Energy businesses. InOctober 2003, uncollectible accounts receivables, allocations for corporate we acquired an additional 15% interest in the Vector Pipeline, support services, and customer service initiatives. Employee bringing our total ownership interest to 40%. The purchase of the' pension and health care benefit costs increased $47 million in .. additional interest in the Vector Pipeline complements our existing 2003 and uncollectible accounts expense increased $17.million- gas distribution and storage facilities in Michigan. Additionally, in 2003 reflecting economic conditions and higher gas prices. we expect to continue to invest in opportunities in the coal bed Partially offsetting these increases were benefits from the DTE methane business to leverage our production, coal and low cost Operating System, as previously discussed, and lower employee operating capabilities.

incentive costs.

CORPORATE & OTHER Capital Resources and Liquidity Corporate & Other includes the administrative and general expenses (inMillions) 2003 2002 2001 of various corporate support functions such as accounting, legal and Cash and Cash Equivalents information technology. As these functions essentially support the Cash Flow From (Used For)-

entire company, they are allocated to the various segments based on Operating activities services utilized and therefore can vary from year to year. Additionally, Net income $ 521 $ 632 $ 332 Corporate & Other holds certain non-regulated debt and investments, Depreciation, depletion and including assets held for sale and in emerging energy technologies. amortization 691 . 759 795 Merger and restructuring charges - - 215 Factors impacting income Corporate & Other's losses were basically Deferred income taxes (220) (208) (7) flat in 2003 and 2002. The 2003 results were affected by a$15 million Gain on sale of assets, net (129) - -

cash contribution to the DTE Energy Foundation that was funded with Working capital and other 87 (187) (524) proceeds received from the sale of ITC (Note 3). The impact of the 950 996 811 contribution was offset by lower interest costs. Results in2002 reflect Investing activities higher interest expense resulting from increased debt and a full years Plant and equipment impact of corporate debt assumed inthe MCN Energy acquisition. expenditures - regulated (679) (794) (776)

Additionally, 2002 results reflect a reserve of $11 million (pre-tax) Plant and equipment expenditures- non-regulated (72) (190) (320) 4 for the possible loss associated with direct loans to and the guarantee of debt of atechnology investment. Losses in 2001 include the Proceeds for sale of ITC, synfuels and otherassets : 758 41 216 amortization of goodwill associated with the MCN Energy acquisition.

Acquisition of MCN Energy - - (1,212)

Restricted cash and:

DISCONTINUED OPERATIONS - ITC other investments 3 (172) (194).

10 (1,115) (2,286)

InDecember 2002, we entered into a definitive agreement with an Financing activities affiliate of Kohlberg Kravis Roberts & Co. and Trimaran Capital'[ Issuance of long-term debt Partners, LLC to sell ITC for $610 million in cash. The sale closed and common stock (1) 571 1,223 4,254 on February 28, 2003 following approval of the transaction by the Redemption of long-term debt (1,208) (613) (1,423)

FERC and resolution of all other contingencies and generated anet Short-term borrowings, net (44) (267) (282) of tax gain of $63 million. Repurchase of common stock (3) (9) (438)

Other, primarily dividends Prior to May 31, 2001, Detroit Edison owned and operated the on common stock (355) (350) (432) transmission assets of ITC, which were vertically integrated with (1,039) (16) 1,679 its other operations. Accordingly, revenues, expenses and cash Net Increase (Decrease) in flows associated with these transmission assets were bundled Cash and Cash Equivalents S (79) $ (135)$ 204 with Detroit Edison's Power Distribution operations. Significant I1)2001 includes $1.75 billion of securitization bonds and $1.35 billion of debt changes in regulation over the past few years required Detroit issued to acquire MCN Energy.

Edison to cede operating control of its transmission assets to an independent system operator or to sell its transmission assets.

OPERATING ACTIVITIES Inresponse to these new requirements we formed ITC and transferred our transmission assets to this wholly-owned subsidiary with the We use cash derived from operating activities to maintain and -

intent of divesting ITC. Effective June 1,2001, the transmission expand our electric and gas utilities and to grow our non-regulated assets of ITC were transferred to DTE Corporate and its revenues, businesses. In addition, we use cash from operations to retire expenses and cash flows were separately monitored to measure its long-term debt and pay dividends. A majority of the company's financial and operating performance. Accordingly, the presentation operating cash flow isprovided by the two regulated utilities, which of discontinued operations in the consolidated statement of are significantly influenced by factors such as 'weather, customer -

operations reflects the results of ITC after May 31, 2001. The choice sales loss, regulatory outcomes, economic conditions and financial results of the transmission business prior to June 1,2001 operating costs. This part of our business has recently been under are included as part of the Power Distribution segment. considerable financial pressure given that we have not had a rate increase in over 10 years, coupled with higher operating costs and CUMULATIVE EFFECT OF ACCOUNTING CHANGES increased regulatory deferrals. While these regulatory deferrals at Detroit Edison have served to mitigate some of the earnings As required by generally accepted accounting principles, on pressures as a result of these influencing factors, the corresponding January 1,2003, we adopted new accounting rules for asset cash flows have been deferred. Our non-regulated businesses also retirement obligations and energy trading activities. The cumulative provide sources of cash flow to the enterprise and reflect a range effect of adopting these new accounting rules reduced 2003 earnings of operating profiles; These vary from our synthetic fuels business, by $27 million. Additionally, on January 1,2001 we adopted a new which will provide substantial cash flow over the next 5years, to accounting rule for derivative instruments and the cumulative effect new start-ups, such as our coal bed methane or waste coal recovery of adopting this new rule increased 2001 earnings by $3million. businesses, which are growing and will require modest investments See Note 2 for further discussion. beyond their cash generation capabilities.

During 2003, our consolidated net cash from operating activities Cash flow from our synfuel business, including proceeds from the was $950 million, reflecting adecrease of $46 million from 2002 sale of interests in related facilities, should shift from a net cash levels. The decrease in 2003 operating cash flow was attributable loss of $195 million in 2003 to positive cash flow of $135 million in to declines in regulated net income, after adjusting for noncash 2004 and $355 million in2005. The expected improvements are driven items (depreciation, depletion, amortization, deferred taxes and by the sale of interests in synfuel facilities, increased production gains), reflecting the impacts of weather, lost electric Customer and a higher cash value per credit. We will also benefit from Choice margins and higher operating costs. Partially offsetting lower taxes paid as we use our tax credit carry forward position.

these declines were lower working capital and other requirements reflecting a company-wide initiative focused on improving cash Our other operating non-regulated businesses will provide minimal flow. The initiative included better inventory management, improved cash from operations in2004 and grow modestly in future years.

accounts receivable collections, the selling of interests in our - Remaining start-up businesses such as coal bed methane, waste synfuel facilities, the monetization of in-the-money derivatives and coal recovery and distributed generation will have cash losses over replacing margin deposits with letters of credit. The improvement the next couple of years while they are being further developed.

in working capital was achieved despite a $222 million contribution Certain of the cash initiatives previously discussed, resulted in to our pension plan. accelerating the receipt of cash in 2003 which will have the impact Operating cash flow in 2002 of $996 million was $185 million higher of lowering cash flow in 2004.

than 2001 levels, largely attributable to the full year's impact of the MCN Energy acquisition, which was completed in May 2001. INVESTING ACTIVITIES Lower working capital and other requirements were partially offset Cash inflows associated with investing activities are partially by a decline in net income, after adjusting for noncash items: Working generated from the sale of assets and utilized to invest in our capital reflects the seasonal requirements of the gas business utilities and rion-regulated businesses. Inany given year, we will where cash isused in the second half of the year to finance look to harvest cash from under performing or non-strategic assets.

increases in gas inventories and customer accounts receivable.

Capital spending within the utility business is primarily to maintain Additionally, past due accounts receivable balances increased due to higher gas prices, economic conditions and conversion issues our generation and distribution infrastructure and comply with with the new combined utility billing system. environmental regulations. We have incurred higher utility capital expenditures over the past several years to comply with new air Outlook- We expect cash flow from operations to increase over quality standards. Capital spending within our non-regulated the long-term, but to remain relatively the same in 2004 as 2003. businesses should be viewed in two categories. For businesses Cash flow improvements from utility rate increases and synfuel currently operating, expenditures are for ongoing maintenance and sales will be offset by higher cash requirements primarily within some expansion. The balance of non-regulated spending isfor growth, our energy marketing and trading business. which we manage very carefully. We look to make investments that meet strict criteria interms of strategy, management skills, Operating cash flow from our utilities isexpected to increase in risks and returns. All new investments are analyzed for their rates 2004, but will be affected by the level of sales migration under the of return and cash payback on a risk adjusted basis. We have electric Customer Choice program and the ability of the MPSC been disciplined in how we deploy capital and will not make within the regulatory processes to put in place a Choice program investments unless they meet our criteria.: For new business lines, that has sound economic fundamentals. Inaddition, the Choice we invest tentatively based on research and analysis. Based on a program's impact will also be determined by the success of the limited investment, we evaluate results and either expand or exit company inaddressing certain structural flaws within the legislative the business based on those results.: In'any given year, the amount process. While the Choice program's shortfalls may be structurally of growth capital will be determined by the underlying cash flows addressed within these two processes, the use of regulatory deferrals of the company with a clear understanding of any potential impact by the MPSC might affect the cash benefits of addressing the on our credit ratings.

existing choice program being realized in 2004.

During 2003, we had net cash from investing activities of $10 million Another factor affecting regulated cash flows is the degree and timing of rate relief within the electric and gas rate cases. Based compared to cash used of $1.1 billion in 2002. The significant on the interim order issued by the MPSC on February 20, 2004, improvement was due to proceeds totaling $758 million from the approximately $71 million of additional revenues should be realized sale of ITC, interests in three synfuel projects and non-strategic ithin the 2004 calendar year. Due to the structure of the interim assets that were acquired as part of the MCN Energy acquisition.

rate order, we will not realize the full benefits of interim and final Additionally, regulated and non-regulated plant expenditures rate relief until 2006 when customer rate caps expire. decreased significantly in2003. Lower regulated expenditures of

$115 million were associated with air quality regulations that require Improvements in cash flow from our utilities are also expected reductions in nitrogen oxide levels. Non-regulated expenditures from better managing our working capital requirements, including declined by $118 million and the comparison reflects costs the continued focus of reducing past due accounts receivables. Our incurred in 2002 associated with four synfuel facilities that emphasis in these businesses will continue to be centered around became fully operational.

cash generation and conservation given the regulatory uncertainties.

elI .

During 2002, the investing activity cash flow comparison improved Our net cash related to financing activities decreased $1.0 billion by $1.2 billion and was impacted by the cash portion of the MCN in 2003 and decreased $1.7 billion in2002. The 2003 change was Energy acquisition in 2001. The 2002 improvement was also due due to higher redemptions of long-term debt and lower proceeds to lower non-regulated capital expenditures, partially offset by from issuances of new debt and common stock. In2002, proceeds reduced proceeds from the sale of assets. from the issuance of debt and common stock were used for the redemption of higher cost debt and to reduce short-term borrowings.

Outlook- Our strategic direction anticipates base level capital The 2001 issuance of $1.75 billion of securitization bonds and the investments and expenditures for existing businesses in 2004 ranging 2001 issuance of $1.35 billion of long-term debt to finance the from $750 million to $1.0 billion. Our utilities plan to spend higher acquisition of MCN Energy impacts the comparison between 2002 amounts of capital, but actual spending levels will be matched to and 2001. In2001, proceeds from the issuance of securitization available cash flows. Until our two rate cases are resolved, we bonds and other Detroit Edison and MichCon debt were used to will hold utility capital spending at 2003 levels. repay higher priced debt and repurchase our common stock.

Details of 2003 financing activities follows (Note 9):

Capital spending for general corporate purposes will increase in 2004 primarily as a result of our DTE2 initiative as subsequently

MichCon issued $200 million of 5.7% senior notes due in discussed. This project will require capital investments in 2004 March 2033. The proceeds were used for debt redemption and and 2005 for new computer systems. Non-regulated capital general corporate purposes.

spending will approximate $80 million to $100 million annually for

DTE Energy issued $400 million of 6-3/8% senior notes due in the next several years. Capital spending for growth of existing or April 2033. Inconjunction with this issuance, DTE Energy new businesses will be constrained in 2004 due to the pending : exchanged $100 million principal amount of existing debt due rate cases, electric Customer Choice issues and rating agency April 2008. The proceeds were used for debt redemptions and concerns about these businesses. Accordingly, we are seeking to general corporate purposes. -

grow the business by making small investments in areas like coal

DTE Energy redeemed $100 million principal amount of 6.17%

bed methane and waste coal recovery. Utilizing this approach Remarketed Notes due in2038.

allows us to determine quarterly our spending levels, which will be

Detroit Edison issued $49 million of 5.5% tax exempt bonds due based on capital and credit constraints. in 2030. The proceeds were used to redeem $49 million of Longer term, once the electric Choice issues are resolved and utility 6.55% tax-exempt bonds due2024.

rate increases are fully phased in,we anticipate capital availability Outlook- Our goal isto maintain a healthy balance sheet. We to return to historical levels. After the utilities return to financial intend on maintaining a high investment grade credit rating and health, we will continue to pursue opportunities to grow our maintaining leverage in the 50%' to 55% range (excluding certain businesses in a disciplined fashion. If we can find opportunities debt, principally securitization debt).

that meet our strategy and financial and risk criteria we will look to make investments. If we have the available cash flow and can't We expect to contribute $170 million of DTE Energy common stock find value creating investments, we intend to return that capital to to our pension plan inthe first quarter of 2004. This contribution shareholders and pay down debt. will modestly improve our leverage. Additionally, we expect to continue the practice of issuing new DTE Energy shares for our We believe that we will have sufficient capital resources, both dividend reinvestment plan. We believe this isa cost-effective internal and external, to balance anticipated-capital requirements.

means of raising new equity.

FINANCING ACTIVITIES Debt maturing in 2004 totals approximately $500 million and we We continually evaluate our leverage targets to ensure that they are called $100 million of Trust preferred- linked securities in late consistent with our objective to have a strong investment grade debt 2003. Inaddition, there are outstanding debt instruments that are rating. Since our merger with MCN Energy in 2001, we have been likely to be economic to redeem and refund with new debt in 2004.

successful in reducing our leverage. Given the present environment The Company expects to continue to take advantage of low historical in our industry, the increase in regulatory assets, and the nature of long-term interest rates and issue new securities with a longer life the electric Customer Choice program and other uncertainties, we than the securities maturing or called..

may need to further lower our leverage inthe future.

As of December 31, 2003, DTE Energy, Detroit Edison and MichCon Our strategy isto have a targeted debt portfolio blend as to fixed and have effective shelf registrations with the SEC that allow for the variable interest rates and maturity. We have completed anumber issuance of up to an additional $1.3 billion of debt and $850 million' of refinancings over the past several years with the effect of extending of equity securities. We have authorization from the DTE Energy the average maturity of our long-term debt. The extension of the Board to repurchase approximately 9.5 million shares of our common average maturity was accomplished at interest rates which have stock. No shares have been repurchased under this authorization lowered our debt costs. Variable rate debt isprincipally in the form since early 2002. Future repurchases are not presently contemplated of outstanding commercial paper. Additionally, we have interest and will depend upon future market conditions and the Company's rate derivatives that effectively converts fixed rate debt to variable financial condition.

rate debt Variable rate debt represents approximately 10% of our total debt outstanding as of December 31, 2003.

II I I ~I I

InOctober 2003, DTE Energy, Detroit Edison and MichCon entered or letters of credit valued at approximately $290 million at into separate revolving credit facilities with a syndicate of banks December 31, 2003. Additionally, our trading business could be totaling $1.3 billion. These facilities support our use of letters of required to cease operations and our access to the short-term -

credit and the issuance of commercial paper. Borrowing available commercial paper market would be restricted or eliminated. While under these revolving credit facilities totaled $1.2 billion as of. we currently do not anticipate such a downgrade, we cannot predict December 31, 2003. Our revolving credit facilities contain customary the outcome of current or future reviews. The following table covenants, including the requirement to maintain a debt to total shows our credit rating as determined by three nationally respected capitalization ratio of not more than .65 to 1,and an earnings credit rating agencies. All ratings are considered investment grade before interest, taxes, depreciation and amortization' (EBITDA) to and affect the value of the related securities.

interest ratio of no less than 2 to 1.As of December 31, 2003, our debt to total capitalization ratio as computed under the terms of Credit Rating Agency the agreement was .50 to 1and our EBITDA to interest ratio was Moody's Standard Investors Fitch 3.6 to 1. We anticipate having the need and the ability to renew & Poors Service Ratings these credit facilities prior to their expiration at fair and reasonable DTE Energy Senior Unsecured Debt BBBE Baa2* BBB market rates as determined at the time of negotiation. DetroitEdison SeniorSecuredDebt A-* A3* A-MichCon Senior Secured Debt BBB+* A2" A Additionally, Detroit Edison has a $200 million short-term financing

Currently on negative outlook agreement secured by customer accounts receivable of which Currently being reviewed for possible downgrade C

$100 million was outstanding as of December 31, 2003. The agreement contains certain covenants related to the delinquency Critical Accounting Estimates of accounts receivable. Detroit Edison iscurrently in compliance with these covenants. There are estimates used in preparing the consolidated financial statements that require considerable judgment. Such estimates For additional information see Note 10 - Short-Term Credit relate to regulation, risk management and trading activities, Arrangements and Borrowings. Section 29 tax credits, goodwill, pension and postretirement costs, and the allowance for doubtful accounts.

CONTRACTUAL OBLIGATIONS The following table details our contractual obligations for debt REGULATION redemptions, leases, purchase obligations and other long-term A significant portion of our business is subject to regulation.

obligations as of December 31, 2003. Detroit Edison and MichCon currently meet the criteria of Statement of Financial Accounting Standards (SFAS) No. 71, L[ps Than 1-3 4-5 Aftar "Accounting for the Effects of Certain Types of Regulation."

(inMillions) Total 1Yea r Years Years 5Years Application of this standard results indifferences in the application Contractual Obligations of generally accepted accounting principles between regulated and Long-Term Debt non-regulated businesses. SFAS No. 71 requires the recording of Mortgage bonds, regulatory assets and liabilities for certain transactions that would notes & other $ 6,006 $ 382 S 1,054 $ 564 $ 4,006 Securitization bonds 1,585 89 312 252 932 have been treated as revenue or expense in non-regulated businesses.

Equity-linked securities 185 7 178 - - Future regulatory changes or changes inthe competitive environment Trust preferred-linked could result in discontinuing the application of SFAS No. 71 for securities 289 -103 - - :186 some or all of our businesses. Ifwe were to discontinue the Capital lease obligations 109 12 36 22 39 application of SFAS No. 71 on all our operations, we estimate that Operating leases 757 72 182 92 411 the extraordinary loss would be as follows:

Electric, gas, fuel, transportation & storage r(n Millions) purchase obligations 10,228 4,269 3,292 1,219 1,448 Other long-term Regulated Entity obligations 802 203 289 161 149 Detroit Edison (1) $ (18)

Total Obligations $19,961 $ 5,137 ' $ 5,343 S 2,310 $ 7,171 MichCon (40)

Total : $ (58)

(1)Excludes securitized regulatory assets CREDIT RATINGS The uncertainty in Michigan's regulatory environment and the impact Management believes that currently available facts support the continued application of SFAS No.'71 and that all regulatory assets of the electric Customer Choice program has resulted invarious independent credit rating agencies reviewing our credit rating. An and liabilities are recoverable or refundable in the current rate unfavorable change in our rating could restrict our ability to access environment (Note 4).

capital markets at attractive rates and increase our borrowing:

costs. We have issued guarantees for the benefit of various RISK MANAGEMENT AND TRADING ACTIVITIES non-regulated subsidiaries. Inthe event that our credit rating is All derivatives are recorded at fair value and shown as "Assets or downgraded two levels and would therefore be below investment liabilities from risk management and trading activities" in the grade, certain of these guarantees would require us to post cash fri I 5

J_

consolidated statement of financial position. Risk management PENSION AND POSTRETIREMENT COSTS activities are accounted for inaccordance with SFAS No. 133,

'Accounting for Derivative Instruments and Hedging Activities," as Our costs of providing pension and postretirement benefits are amended. Through December 2002, trading activities were accounted dependent upon a number of factors, including rates of return on for in accordance with Financial Accounting Standards Board (FASB) plan assets, the discount rate, the rate of increase inhealth care Emerging Issues Task Force (EITF) Issue No. 98-10, "Accounting for costs and the amount and timing of plan sponsor contributions.

Energy Trading and Risk Management Activities." Effective January We had pension costs for qualified pension plans of $47 million in 2003, trading activities are accounted for in accordance with SFAS 2003, pension income of $9million in 2002 and pension costs of No. 133. See Note 2- New Accounting Pronouncements.

$159 million in 2001. Postretirement benefits costs for all plans The offsetting entry to "Assets or liabilities from risk management was $118 million in 2003, $70 million in 2002 and $104 million in and trading activities isto other comprehensive income or earnings 2001. Pension and postretirement benefits cost is calculated based depending on the use of the derivative, how it is designated and if upon a number of actuarial assumptions, including an expected it qualifies for hedge accounting. The fair values of derivative long-term rate of return on our plan assets of 9.0% at December contracts were adjusted each reporting period for changes using 31, 2003. Indeveloping our expected long-term rate of return market sources such as: assumption, we evaluated input from our consultants, including their review of asset class risk and return expectations as well as published exchange traded market data inflation assumptions. Projected returns by such consultants are

prices from external sources based on broad equity and bond markets. Our expected long-term

price based on valuation models rate of return on plan assets is based on an asset allocation assumption utilizing active investment management of 65% in Market quotes are more readily available for short duration contracts. equity markets, 28% in fixed income markets, and 7%invested in Derivative contracts are only marked to market to the extent that other assets. Because of market volatility, we periodically review markets are considered highly liquid where objective, transparent our asset allocation and rebalance our portfolio when considered prices can be obtained. Unrealized gains and losses are fully appropriate. Given market conditions we believe that 9.0% is a reserved for transactions that do not meet this criterion. reasonable long-term rate of return on our plan assets. We will continue to evaluate our actuarial assumptions, including our SECTION 29 TAX CREDITS expected rate of return, at least annually.

We have generated Section 29 tax credits from our synfuel, coke We base our determination of the expected return on qualified battery, biomass and gas production operations. All of our synthetic plan assets on a market-related valuation of assets, which reduces fuel facilities have received favorable private letter rulings from year-to-year volatility. This market-related valuation recognizes the IRS with respect to their operations. All Section 29 tax credits changes in fair value in a systematic manner over a three-year taken after 1997 are subject to audit by the IRS, and if we fail to period. Because of this method, the future value of assets will prevail through the administrative and legal process, there could be impacted as previously deferred gains or losses are recorded.

be a significant tax liability owed for previously taken Section 29 We have unrecognized net losses due to the recent unfavorable tax credits. Four of our synfuel facilities are under audit by the IRS performance of the financial markets. As of December 31, 2003, for 2001 and are expected to be completed in 2004. Our portion of we had $7million of cumulative losses that remain to be recognized tax credits generated was $241 million in 2003 as compared to in the calculation of the market-related value of assets.

$250 million in 2002 and $165 million in 2001. Outside firms assist us in assuring we operate in accordance with our private letter The discount rate that we utilize for determining future pension rulings and within the parameters of the law, as well as calculating and postretirement benefit obligations isbased on areview of bonds the value of tax credits. that receive one of the two highest ratings given by a recognized rating agency. The discount rate determined on this basis has GOODWILL decreased from 6.75% at December 31, 2002 to 6.25% at December 31, 2003. Due to recent financial market performance, Certain of our business units have goodwill resulting from purchase lower discount rates and increased health care trend rates, we.

business combinations (Note 2). Inaccordance with SFAS No. 142, estimate that our 2004 pension costs will approximate $100 million "Goodwill and Other Intangible Assets," each of our reporting units compared to $54 million in2003 and our 2004 postretirement benefit with goodwill is required to perform impairment tests annually or costs will approximate $135 million compared to $118 million in2003.

whenever events or circumstances indicate that the value of goodwill We have made modifications to the pension and postretirement may be impaired. Inorder to perform these impairment tests, we benefit plans to mitigate the earnings impact of higher costs.

must determine the reporting unit's fair value using valuation Future actual pension and postretirement benefit costs will depend techniques, which use estimates of discounted future cash flows on future investment performance, changes in future discount rates to be generated by the reporting unit. These cash flow estimates and various other factors related to plan design.

involve judgments based on a broad range of information and historical results. To the extent estimated cash flows are revised Lowering the expected long-term rate of return on our plan assets downward, the reporting unit may be required to write down all or by 1.0% would have increased our 2003 qualified pension costs by a portion of its goodwill which would adversely impact our eamings. approximately $22 million. Lowering the discount rate and the Based on our 2003 goodwill impairment test, we determined that salary increase assumptions by 1.0% would have increased our no impairment existed. As of December 31, 2003, our goodwill pension costs for 2003 by approximately $11 million. Lowering the totaled $2.1 billion. health care cost trend assumptions by 1.0% would have decreased III

'i

our postretirement benefit service and interest costs for 2003 by Environmental Matters approximately $16 million.

Protecting the environment, as well as correcting past environmental The market value of our pension and postretirement benefit plan damage, continues to be a focus of state and federal regulators.

assets has been affected by declines inthe financial markets in Legislation and (or) rulemaking could further impact the electric recent years. The value of our plan assets decreased from $2.8 billion utility industry including Detroit Edison. The Environmental at December 31, 2001, to $2.4 billion at December 31, 2002. The Protection Agency (EPA) and the Michigan Department of value at December 31, 2003 increased to $2.9 billion. The investment Environmental Quality have aggressive programs to clean-up performance returns and declining discount rates required us to contaminated property.

recognize at December 31, 2002, an additional minimum pension liability of $855 million, an intangible asset of $57 million and an The EPA ozone transport regulations and final new air quality entry to other comprehensive loss (shareholders' equity) of $518 standards relating to ozone and particulate air pollution will million, net of tax. As of December 31, 2003, we recognized a continue to impact us. Detroit Edison has spent approximately decrease in minimum pension liability of $75 million, adecrease in $560 million through December 2003 and estimates that it will intangible assets of $13 million and adecrease inother comprehensive spend approximately $40 million in 2004 and incur up to an loss (acomponent of shareholders' equity) of $647 million ($421 additional $1.2 billion of future capital expenditures over the next million after tax). The additional minimum pension liability and five to eight years to satisfy both existing and proposed new control related accounting entries will be reversed on the balance sheet in requirements. Recovery of costs to be incurred through December future periods if the fair value of plan assets exceeds the accumulated 2004 is included in our June 2003 electric rate case. Inaddition, we pension benefit obligations. The recording of the minimum pension maintain the option to securitize these costs after the completion liability does not affect net income or cash flow. of our current regulatory proceedings.

Pension and postretirement costs and pension cash funding The EPA has initiated enforcement actions against several major, requirements will increase in future years without a substantial electric utilities citing violations of the Clean Air Act, asserting recovery in the financial markets. We made a $35 million cash that older, coal-fired power plants have been modified inways that contribution to the pension plan in 2002 and a $222 million cash would require them to comply with the more restrictive 'new contribution in 2003. We anticipate making an approximately $170 - source' provisions of the Clean Air Act. Detroit Edison received million contribution to our pension plan in the form of DTE Energy and responded to information requests from the EPA on this subject.

common stock in the first quarter of 2004. We also contributed The EPA has not initiated proceedings against Detroit Edison. The

$33 million to the postretirement plans in 2002. We did not United States District Court for the Southern District of Ohio contribute to the postretirement plans in 2003, and made a $40 Eastern Division issued adecision in August 2003 finding Ohio million contribution in January 2004. Edison Company inviolation of the new source provisions of the Clean Air Act. If the Court's decision is upheld, the electric utility InDecember 2003, the Medicare Prescription Drug, Improvement industry could be required to invest substantial amounts in pollution and Modernization Act was signed into law. This Act provides for a control equipment. During the same month, however, a district federal subsidy to sponsors of retiree health care benefit plans court in a different division rendered a conflicting decision on the that provide a benefit that is at least actuarially equivalent to the matter. On August 27. 2003, the EPA released new rules, effective benefit established by law. We have not quantified the impact of December 26, 2003, allowing repair, replacement or upgrade of the Act, if any, on our plan. production equipment without triggering source requirement controls if the cost of the parts and repairs do not exceed 20% of the replacement value of the equipment being upgraded. Such repairs ALLOWANCE FOR DOUBTFUL ACCOUNTS will be considered routine maintenance, however any changes in We establish an allowance for doubtful accounts based upon factors emissions would be subject to existing pollution permit limits and surrounding the credit risk of specific customers, historical trends, other state and federal programs for pollutants. Several states and economic conditions, age of receivables and other information. environmental organizations have challenged these regulations and With the implementation of a new integrated utility billing system on December 24, 2003, were granted a stay until the U.S. Court of in late 2001, we encountered billing issues as istypical with Appeals D.C. Circuit hears the arguments on the case. We cannot large-scale system implementations. While we have resolved the predict the future impact of this issue upon Detroit Edison.

primary billing issues, we may encounter difficulty in collecting past due receivables. Higher customer bills due to increased gas prices, the lack of adequate levels of assistance for low-income DTE Energy Operating System and DTE2 customers and economic conditions have also contributed to the During 2002, we adopted The DTE Energy Operating System, which increase in past due receivables. As a result of these factors, our is a philosophy that involves the application of tools and operating allowance for doubtful accounts increased in2002 and 2003. We practices that have resulted in inventory reductions and improve-believe the allowance for doubtful accounts isbased on reasonable ments in technology systems, among other enhancements.

estimates. However, failure to make continued progress in collecting Operation and maintenance expenses benefited from our company-our past due receivables would unfavorably affect wide initiative to pursue cost efficiencies and enhance operating operating results and cash flow. performance. We expect continued cost containment efforts and process improvements.

In2003, we began the implementation of DTE2, a company-wide FairValue of Contracts initiative to improve existing processes and to implement new core information systems including, finance, human resources, supply The following disclosures are voluntary and have been developed chain and work management. We expect to incrementally spend through efforts of the Committee of Chief Risk Officers, aworking approximately $150 million to $175 million over the next 3 to 4 group of chief risk officers from companies active in both physical years to implement these nev processes and systems. We expect and financial energy trading and marketing. We believe the the benefits to outweigh this investment primarily from lower disclosures provide enhanced transparency of the activities and costs, faster business cycles, repeatable and optimized processes, position of our Energy Trading & Marketing segment.

enhanced internal controls, improvements in inventory management and reductions in system support costs. ROLL-FORWARD OF MARK TO MARKET ENERGY CONTRACT NET ASSETS New Accounting Pronouncements. The following table provides details on changes in our mark to market (MTM) net asset or (liability)'position during 2003.

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

P S, I"'--'

' '- 'Proprietary Strucltured Owned Energy I Gas -

(inMillions) : Trading(1) Contracts (2) Assets (3) Trading Total Production Total Energy Marketing & Trading Segment MTM at December31, 2002 $ 15 $ 19 $ (50) $ (16) $ (79) $ (95)

Reclassed to realized upon settlement (5) (15) 14 (6) 27 21 Uiquidationrof in-the-money positions (4) - - (136) (136) - (136)

Changes infairvalue 11 12 (16) 7 - 7 Amortization of option premiums (9) - - (9) - (9) I Amounts impacting unrealized income (3) (3) (138) (144) 27 (117)

Cumulative effectadjustment(5) (2) (1) 17 14 - 14 Effective portion of change in fair value - 2 - 2 (28) (26)

MTM at December31, 2003 $ 10 $ 17 $0171) $(144) $ (80) $(224)

(11)'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 intentto capture profits by originating substantially hedged 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 asuitable offsetting trade can be executed.

(3)'Owned Assets' represent derivative activity associated with assets owned by DTE Energy, including forward sale's of gas production and trades associated with owned transportation and storage capacity. Derivatives are generally executed with the intent of locking inand optimizing profits without creating additional risk.

(4)Inconjunction with our overall tax planning and cash initiatives, we monetized certain in-the-money contracts in2003 while simultaneously entering into at-the-market contracts with various counterparties. This had the impact of optimizing taxable income and cash flow while having minimal impact on reported earnings.

(5)Excludes the cumulative effect adjustment associated with the change inaccounting for gas inventory (Note 2). i Proprietary Structured Owned Energy Gas Total Assets (inMillions) Trading Contracts Assets Eliminations Trading Total Production (Uabilities) I Currentassets : $ 91 $ 44 $ 98 $ (45) $ 188 $ - $188 Noncurrent assets 13 27 57 (7) 90 - 90 i Total MTM assets 104 71 155 (52) 278 - 278 i i

ii Current liabilities (79) (32) (219) 44 (286) (42) (328)

Noncurrent liabilities (15) (22) (107) 8 (136) (38) (174) 7 Total MTM liabilities (94) (54) (326) 52 (422) (80) (502) I Total MTM net assets I (liabilities) ' $ 10 $ 17 $(171) $ - $S144) $ (80) $(224) - i i

iI i-I i

i ii, E= I, -

MATURITY AND SOURCE OF FAIR VALUE OF MTM (inMillions) Increase Decrease Change in the Activitv of 10% of 10% fair value Of ENERGY CONTRACT NET ASSETS We fully reserve all unrealized gains and losses related to periods Gas Contracts $ (8) $ 9 Commodity contracts beyond the liquid time frame. Our intent isto recognize MTM Power Contracts $ (8) $ 8 Commodity contracts activity only when pricing data isobtained from active quotes and Interest Rate Risk $ (303) $ 323 Long term debt published indexes. The table below shows the maturity of the Foreign Currency Risk $ .2 $ 1.2) Forward contracts MTM positions of our energy contracts.

CREDIT RISK (inMillions) 2007 Total and Fair Source of Fair Value 2004 2005 2006 Beyond Value Bankruptcies ProprietaryTrading $ 13 $ (3)$ - S $- 10 We purchase and sell electricity, gas, coal and coke from and to Structured Contracts 11 5 - 1 17 numerous companies operating in the steel, automotive, energy OwnedAssets (121) (391 (11) (171)

EnergyMarketing&Trading (97) (37) (11) 1 (144) and retail industries. "A number of customers have filed for Gas Production (42) (301 (8) - (80) bankruptcy protection under Chapter 11 of the U.S. Bankruptcy 1 $ (224)

Code. We have negotiated or are currently involved innegotiations Total $ 1139) $ (67) $ (19) $

with each of the companies, or their successor companies, that have filed for bankruptcy protection. We regularly review contingent Quantitative and Qualitative matters relating to purchase and sale contracts and record Disclosures About Market Risk provisions for amounts considered probable of loss. We believe our accrued amounts are adequate for probable losses. The final COMMODITY PRICE RISK resolution of these matters is not expected to have a material effect on our financial statements in the period they are resolved.

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. Energy Trading & CoEnergy Portfolio We also are exposed to the risk of market price fluctuations on gas We utilize both external and internally generated credit sale and purchase contracts, gas production and gas inventories. assessments when determining the credit quality of our trading To limit our exposure to commodity price fluctuations, we have counterparties. The following table displays the credit quality of entered into a series of electricity and gas futures, forwards, our trading counterparties.

option and swap contracts. See Note 15 - Financial and Other Credit Exposure Derivative Instruments for further discussion. before Cash Cash Net Credit (inMillions) Collateral Collateral Exposure INTEREST RATE RISK Investment grade (1)

A- and Greater $ 215 $ (22) $ 193 DTE Energy is subject to interest rate risk in connection with the BBB+ and BBB 157 - 157 issuance of debt and preferred securities.' In order to manage 3 BBB- 3 -

interest costs, we use treasury locks and interest rate swap agreements. Our exposure to interest rate risk arises primarily Total Investment Grade 375 . (22) 353

'Non-investment grade (2) 4 I (2) 2 from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR). Internally Rated -

inwa<1mantnrerl 1-2 59 (3) . 56 Internally Rated -

FOREIGN CURRENCY RISK non-investment grade (4) 4 - 4 DTE Energy has foreign currency exchange risk arising from market t I Total $ 442 $ (27) $ 415 price fluctuations associated with fixed priced contracts:. These contracts are denominated in Canadian dollars and are primarily (1)This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody's Investor Service (Moody's) and BBB- assigned by for the purchase and sale of power as well as for long-term Standard & Poor's Rating Group (Standard & Poor's). The five largest transportation capacity. To limit our exposure to foreign currency counterparty exposures combined for this category represented 39% of fluctuations, we have entered into a series of currency forward- the total gross credit exposure.

contracts through 2008. -: '(2) This category includes counterparties with credit ratings that are below investment grade. The five largest counterparty exposures combined for this category represented less than 1%of the total gross credit exposure.

SUMMARY

OF SENSITIVITY ANALYSIS (3)This category includes counterparties that have not been rated by Moody's or Standard & Poor's, but are considered investment grade based on DTE We performed a sensitivity analysis calculating the impact of Energy's evaluation of the counterpartys creditworthiness. The five largest changes in fair values utilizing applicable forward commodity rates counterparty exposures combined for this category represented 7%of the or changes in interest rates if they occurred at December 31, 2003: total gross credit exposure.

(4)This category includes counterparties that have not been rated by Moody's or Standard & Poor's, and are considered non-investment grade based on DTE Energy's evaluation of the counterpartys creditworthiness. The five largest counterparts exposures combined for this category represented less than 1%of the gross credit exposure.

II III ,

DTE ENERGY COMPANY -:

Report of Management's- Responsibility for Financial Statements We have reviewed this annual report to shareholders, and (b) evaluated the effectiveness of our disclosure controls and based on our knowledge, this annual report does not contain any procedures as of the end of the period covered by this annual untrue statement of a material fact or omit to state a material report; and fact necessary to make the statements made, in light of the circumstances under which such statements were made, not (c) have concluded that such controls and procedures were misleading with respect to the period covered by this annual effective at ensuring that required information is disclosed report. Also, based on our knowledge, the financial statements, on a timely basis.

and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of DTE Energy as of, and for, the periods presented. Anthony F.Earley, Jr.

Chairman, President, Chief Executive and We are responsible for establishing and maintaining disclosure Chief Operating Officer controls and procedures (as defined inSecurities and Exchange Act Rules 13a-15(e) and 15d-15(e)) and we have:

(a)designed such disclosure controls and procedures to ensure - David E.Meador

- that material information is made known to us by others Senior Vice President and Chief Financial Officer within our company, particularly during the period in which this annual report isbeing prepared; : :

Independent Auditors' Report test basis, evidence supporting the amounts and disclosures in the Deloitte. financial statements. An audit also includes assessing the accounting Deloitte & Touche LLP principles used and significant estimates made by management, as Suite 900 well as evaluating the overall financial statement presentation.

600 Renaissance Center We believe that our audits provide a reasonable basis for our opinion.

Detroit, Michigan 48243-1704 Inour opinion, such consolidated financial statements present fairly, in all material respects, the financial position of DTE Energy -

To the Board of Directors and Shareholders . .. Company and subsidiaries at December 31, 2003 and 2002, and of DTE Energy Company the results of their operations and their cash flows for each of the.

three years in the period ended December 31, 2003 in conformity We have audited the consolidated statement of financial position with accounting principles generally accepted in the United of DTE Energy Company and subsidiaries (the 'Company") as of States of America.

December 31, 2003 and 2002, and the related consolidated statements of operations, cash flows and changes in shareholders' equity and As discussed in Note 2to the consolidated financial statements, in comprehensive income for the each of the three years in the period connection with the required adoption of certain new accounting ended December 31, 2003. These financial statements are the principles, in 2003 the Company changed its method of accounting responsibility of the Company's management. Our responsibility is for asset retirement obligations, energy trading contracts and gas to express an opinion on the consolidated financial statements inventories; in 2002 the Company changed its method of accounting based on our audits. for goodwill and energy trading contracts; and in 2001 the Company changed its method of accounting for derivative instruments and We conducted our audits in accordance with auditing standards hedging activities.

generally accepted inthe United States of America. Those standards require that we plan and perform the audit to obtain

- p :-

reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a March 1,2004 III 'I

DTE ENERGY COMPANY Consolidated Statement of Operations Year Ended December 31 (inMillions, Exceptper Share Amounts) 2003 2002 2001 Operating Revenues S 7,041 $ 6,729 $ 5,787 Operating Expenses Fuel, purchased power and gas 2,241 2,099 1,919 Operation and maintenance 3,032 2,547 1,848 Depreciation, depletion and amortization 687 737 782 Taxes otherthan income 334 352 305 Merger and restructuring charges (Note 3) - - 268 6,294 5,735 5,122 Operating Income 747 994 665 Other (Income) and Deductions Interest expense 546 569 482 Interest income (37) (29) (22)

Minority interest (91) (37)

Other income (138) (62) (60)

Other expenses 110 51 75 390 492 475 Income Before Income Taxes 357 .502 190 Income Tax Benefit (Note 7( 1123) (84) (119)

Income from Continuing Operations 480 586 309 Income from Discontinued Operations of ITC, net of tax (Note 3) 68 46 20 Cumulative Effect of Accounting Changes, net of tax (Note 2) (27) - 3 Net Income S 521 $ 632 $ 332 Basic Earnings per Common Share (Note 8)

Income from continuing operations $ 2.87 $ 3.57 $ 2.02 Discontinued operations .41 .28 .13 Cumulative effect of accounting changes (.17) - .02 Total $ 3.11 $ 3.85 $ 2.17 Diluted Earnings per Common Share (Note 8)

Income from continuing operations - 2.85 $ 3.55 $ 2.01 Discontinued operations .40 .28 .13 Cumulative effect of accounting changes (.16) - .02 Total $ 3.09 $ 3.83 $ 2.16 Average Common Shares Basic 168 164 153 Diluted 168 165 154 Dividends Declared per Common Share S 2.06 $ 2.06 $ 2.06 See Notes to Consolidated Financial Statements

,jI I 'i 'U

DTE ENERGY COMPANY Consolidated Statement of Financial Position i~

December 31 (inMillions) 2003 2002 I ,.

ASSETS Current Assets Cash and cash equivalents $ 54 $ 133 Restricted cash 131

237 Accounts receivable Customer (less allowance for doubtful accounts of $99 and $82, respf 877 902 Accrued unbilled revenues 316 296 Other . 338 - 237 Inventories Fuel and gas 467 413 Materials and supplies 162 163 Assets from risk management and trading activities 186 224 Other 181 159 Z712 2Z764 Investments Nuclear decommissioning trust funds 518 417 Other 601 496 1,119 913 Property Property, plant and equipment 17,679 17,862 Less accumulated depreciation and depletion (Note 2) (7,355) (7,320) 10,324 10,542 Other Assets Goodwill (Note 3). 2067 2,112 Regulatory assets (Note 4) Z063 1,197 Securitized regulatory assets (Note 4) 1,527 1,613 Notes receivable 469 336 Assets from risk management and trading activities 88 152 Prepaid pension assets 181 172 Other 203 184 6,598 5,766 Total Assets $ 20,753 $ 19,985 See Notes to Consolidated Financial Statements II I '1 I.

December 31 (inMillions, Except Shares) 2003 2002 LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities Accounts payable $ 625$ 647 Accrued interest 110 115 Dividends payable 87 90 Accrued payroll 51 49 Income taxes 185 44 Short-term borrowings 370 414 Current portion long-term debt, including capital leases 477 1,018 Liabilities from risk management and trading activities 326 262 Other 648 552 2,879 3,191 Other Liabilities Deferred income taxes 988 916 Regulatory liabilities (Notes 2 and 4) 817 179 Asset retirement obligations (Note 2) 866 Asset removal costs (Note 2] - 729 Unamortized investment tax credit 156 168 Liabilities from risk management and trading activities 173 208 Liabilities from transportation and storage contracts 495 545 Accrued pension liability 345 582 Deferred gains from asset sales 311 161 Minority interest 156 128 Nuclear decommissioning (Notes 2 and 5) 67 416 Other 544 394 4,918 4,426 Long-Term Debt (net of current portion) (Note 9)

Mortgage bonds, notes and other 5,624 5,656 Securitization bonds 1,496 1,585 Equity-linked securities 185 191 Trust preferred-linked securities 289 289 Capital lease obligations 75 82 7,669 7,803 Commitments and Contingencies (Notes 4,5 and 13)

Shareholders' Equity Common stock, without par value, 400,000,000 shares authorized, 168,606,522 and 167,462,430 shares issued and outstanding, respectively 3,109 3,052 Retained earnings Z308 2,132 Accumulated other comprehensive loss (130) (619) 5,287 4,565 Total Liabilities and Shareholders' Equity . $ 20,753 $ 19,985 See Notes to Consolidated Financial Statements mma,,.,q V

DTE ENERGY COMPANY Consolidated Statement of Cash Flow I Year Ended December 31 (in Millions) 2003 2002 2001 Operating Activities Net income $ 521 $ 632 $ 332 Adjustments to reconcile net income to net cash from operating activities:

Depreciation, depletion and amortization 691 759 795 Merger and restructuring charges 215 Deferred income taxes (220) (208) 17)

Gain on sale of assets, net (129)

Partners' share of synfuel project losses (78) (40)

Contributions from synfuel partners 65 22 Cumulative effect of accounting changes 27 3 Changes in assets and liabilities, exclusive of changes shown separately (Note 1) 73 (169) (527)

Net cash from operating activities 950 996 811 Investing Activities Plant and equipment expenditures - regulated (679) (794) (776)

Plant and equipment expenditures - non-regulated (72) (190) (320)

Acquisition of MCN Energy, net of cash acquired - - (1,212)

Proceeds from sale of interests in synfuel projects 89 32 Proceeds from sale of ITC and other assets 669 9 216 Restricted cash for debt redemptions 106 (79) (70)

Other investments (103) (93) (124)

Net cash from (used for) investing activities 10 (1,115) (2,286)

Financing Activities Issuance of long-term debt 527 958 4,254 Redemption of long-term debt (1,208) (613) (1,423)

Issuance of trust preferred-linked securities 180 Redemption of trust preferred-linked securities - (180)

Short-term borrowings, net (44) (267) (282)

Capital lease obligations (9) (12) (107)

Issuance of common stock 44 265 Repurchase of common stock (3) (9) (438)

Dividends on common stock (346) (338) (325)

Net cash from (used for) financing activities (1,039) (16) 1,679 Net Increase (Decrease) in Cash and Cash Equivalents (79) (135) 204 I Cash and Cash Equivalents at Beginning of Period 133 268 64 ! I

1. ,

Cash and Cash Equivalents at End of Period $ 54 $ 133 $ 268 Sea Notes to Consolidated Financial Statements I Iif

DTE ENERGY COMPANY Consolidated Statement of [

Changes in Shareholders' Equity and Comprehensive Income Common Stock Retained Accumulated Other (Dollars inMillions, Shares inThousands) Shares Amounts Earnings Comprehensive Loss Total Balance, December31,2000 142,651 $ 1,912 $ 2,097 $ - $ 4,009 Net income - - 332 - 332 Issuance of new shares 29,017 1,060 - - 1,060 Dividends declared on common stock - - (324) - (324)

Repurchase and retirement of common stock (10,534) 1155) (270) - (425)

Unearned stock compensation - (6) - - (6)

Net change in unrealized losses on derivatives, net of tax - - - (69) (69)

Net change inunrealized gain on investments, net of tax - - - 1 Other - - 11 - 11 Balance, December 31, 2001 161,134 2,811 1,846 (68) 4,589 Net income - - 632 - 632 Issuance of new shares 6,426 270 - - 270 Dividends declared on common stock - - (341) _ (341)

Repurchase and retirement of common stock (98) (1) (2) - (3)

Pension obligations (Note 14) - - - (518) (518)

Net change inunrealized losses on derivatives, net of tax - - - (33) (33)

Other - (28) (3) - (31)

Balance, December31,2002 167,462 3,052 2,132 (619) 4,565 Net income - - 521 - 521 Issuance of new shares -1,225 57 - - 57 Dividends declared on common stock - - (348) _ (348)

Repurchase and retirement of common stock (80) (1) - - (1)

Pension obligations (Note 14) - - - 420 420 Net change inunrealized losses on derivatives, net of tax - - - 17 17 Net change inunrealized gain on investments, net of tax - - - 52 52 Other - 1 3 - 4 Balance, December 31, 2003 168,607 S 3,109 $ 2,308 $ (130) $ 5,287 The following table displays comprehensive income (loss):

(inMillions) 2003 2002 2001 Net income $ 521 $ 632 $ 332 Other comprehensive income (loss), net of tax:

Net unrealized losses on derivatives:

Gains or (losses) arising during the period, net of taxes of $(8), $32 and $29 16 (60) (53)

Amounts reclassified to earnings, net of taxes of $-,$(15) and $(14) 1 27 26 Cumulative effect of a change in accounting, net of taxes of -, S-and $24 - - (42) 17 (33) (69)

Net change inunrealized gain on investments, net of taxes of $(28), $-and $(1) 52 - 1 Pension obligations, net of taxes of 5(226), $280 and $- 420 (518) -

Comprehensive income $ 1,010 $ 81 $ 264 See Notes to Consolidated Financial Statements II I ,

I DTE ENERGY COMPANY NOTES I to. consolidatedI financial statements NOTE 1- Significant Accounting Policies REVENUES Revenues from the sale and delivery of electricity, and the sale, CORPORATE STRUCTURE delivery and storage of natural gas are recognized as services are DTE Energy isan exempt holding company under the Public Utility provided. Detroit Edison and MichCon record revenues for electric Holding Company Act of 1935 and owns the following businesses: and gas provided but unbilled at the end of each month. Under agreement with the MPSC, Detroit Edison was not allowed to raise

Detroit Edison Company (Detroit Edison), an electric utility rates through 2003. Through December 2001, MichCon's rates included engaged in the generation, purchase, distribution and sale of acomponent for cost of gas sold that was fixed at $2.95 per thousand electric energy to 2.1 million customers in southeast Michigan; cubic feet (Mcf). In2002, MichCon reinstated the gas cost recovery

Michigan Consolidated Gas Company (MichCon), a natural gas (GCR) mechanism that recovers the prudent and reasonable cost of utility engaged in the purchase, storage, transmission and gas sold subject to annual proceedings before the MPSC.

distribution and sale of natural gas to 1.2 million customers throughout areas of Michigan; and Non-regulated revenues are recognized as services are provided

Other non-regulated subsidiaries engaged in energy marketing and products are delivered.

and trading, energy services and various other electricity, coal and gas related businesses. - Since 2002, the FASB has issued significant accounting guidance that governs energy trading revenue recognition and classification.

Detroit Edison and MichCon are regulated by the Michigan Public See Note 2- New Accounting Pronouncements for additional detail.

Service Commission (MPSC). The Federal Energy Regulatory Commission (FERC) regulates certain activities of Detroit Edison's business as well as various other aspects of businesses under DTE COMPREHENSIVE INCOME Energy. Inaddition, we are regulated by other federal and state We comply with SFAS No. 130, "Reporting Comprehensive Income,'

regulatory agencies including the Nuclear Regulatory Commission that established standards for reporting comprehensive income.

and the Environmental Protection Agency, among others. SFAS No. 130 defines comprehensive income as the change in common shareholders' equity during a period from transactions and References inthis report to 'we", "us', "our' or "Company' are to events from non-owner sources, including net income. As shown DTE Energy and its subsidiaries, collectively.

in the following table, amounts recorded to other comprehensive income include unrealized derivative gains and losses under SFAS PRINCIPLES OF CONSOLIDATION No. 133, "Accounting for Derivative Instruments and Hedging We consolidate all majority owned subsidiaries and investments Activities, "unrealized gains and losses on available for sale securities in entities inwhich we have controlling influence. Non-majority under SFAS No. 115, "Accounting for Certain Investments in Debt owned investments are accounted for using the equity method when andEquitySecurities,"and minimum pension liabilities as prescribed the company isable to influence the operating policies of the investee. by SFAS No. 87, "Employers'Accounting for Pensions, "at December Non-majority owned investments include investments in limited 31, 2003. The minumum pension liability was reclassified to a liability companies, partnerships or joint ventures. When we do regulatory asset during 2003 (Note 4).

not influence the operating policies of an investee, the cost method Net .Net: Minimum Accumulated isused. We eliminate all intercompany balances and transactions. Unrealized , Unrealized Pension Other Losses onD Gains on Liability Comprehensive (inMillions) DerivativesI Investments Adjustment income For entities that are considered variable interest entities we Beginning balance $ (102) ! $ 1 $ (518) $ (619):

apply the provisions of FASB Interpretation No. (FIN) 46-R, Current-period "Consolidation of Variable Interest Entities, an Interpretation of change 17 52 420 489 ARB No. 51. " For a detailed discussion of FIN 46-R see Note 2 - Ending balance. . $ (85) $ 53 $ (98) $ (130)

New Accounting Pronouncements.

INVENTORIES BASIS OF PRESENTATION We value fuel inventory and materials and supplies at average cost.

The accompanying consolidated financial statements are prepared Gas inventory at MichCon isdetermined using the last-in, first-out using accounting principles generally accepted in the United States (LIFO) method. At December 31, 2003, the replacement cost of gas of America. These accounting principles require us to use estimates remaining in storage exceeded the $117 million LIFO cost by $251 and assumptions that impact reported amounts of assets, liabilities, million. At December 31, 2002, the replacement cost exceeded revenues and expenses, and the disclosure of contingent assets the $55 million LIFO cost by $187 million. During 2001, MichCon and liabilities. Actual results may differ from our estimates. liquidated 2.1 billion cubic feet (Bcf) of prior years' LIFO layers at an average cost of $0.39 per Mcf. MichCon's average gas purchase We reclassified certain prior year balances to match the current rate in 2001 was $2.83 per Mcf higher than the average LIFO year's financial statement presentation.

'I cIz

' 'I a Ii

liquidation rate. Applying LIFO cost in valuing the liquidation, as - Property isstated at cost and includes construction-related opposed to using the average purchase rate, decreased 2001 cost of labor, materials and overheads. The cost of properties retired, gas by $5.8 million and increased earnings by $3.8 million, net of taxes. less salvage, at Detroit Edison and MichCon are charged to accumulated depreciation.

Through December 2002, the Energy Marketing &Trading segment used the fair value method to price gas inventories. To comply - - Expenditures for maintenance and repairs are charged to expense with the accounting requirements resulting from the rescission of when incurred, except for Fermi 2.Approximately $37 million of Emerging Issues Task Force (EITF) Issue No. 98-10, 'Accounting for expenses related to the anticipated Fermi 2 refueling outage Energy TradingActivities and Risk ManagementActivities," the scheduled for 2004 are being accrued on a pro-rata basis over an Energy Marketing & Trading segment changed to the average cost 18-month period that began in May 2003. We have utilized the method for its gas inventories, effective January 2003. accrue-in-advance policy for nuclear refueling outage costs since the Fermi 2 plant was placed in service in 1988. This method PROPERTY, RETIREMENT AND MAINTENANCE, also matches the regulatory recovery of these costs in rates set AND DEPRECIATION AND DEPLETION by the MPSC.

Summary of property by classification as of December 31: We base depreciation provisions for utility property at Detroit (inMillions) 2003 2002 Edison and MichCon on straight-line and units of production rates Property, Plant and Equipment approved by the MPSC. The composite depreciation rate for Electric Utility Detroit Edison was 3.4 %in 2003, 2002 and 2001. The composite Generation $ 6,938 $ 6,515 depreciation rate for MichCon was 3.5%, 3.6% and 3.9% in 2003, Distribution 5,733 5,606 2002 and 2001, respectively.

Transmission (1) - 813 Total Electric Utility 1Z671 12,934 The average estimated useful life for each class of property, plant Gas Utility and equipment as of December 31, 2003 follows:

Distribution 1,961 1,903 Estimated Useful Lives inYears Storage 224 212 Utility Generation Distribution Transmission (1)

Other 855 906 Electric 39 37 -

Total Gas Utility 3,040 3,021 Gas N/A 26 28 Energy Services Coal Based Fuels 652 636 1l)The electric transmission assets were sold inFebruary 2003.

On-Shte Energy 180 172 Merchant Generation 229 228 Non-regulated property isdepreciated over its estimated useful life Other 13 9 using straight-line, declining-balance or units-of-production methods.

Total Energy Services 1,074 1,045 We credit depreciation, depletion and amortization expense Other non-regulated and other 894 862 when we establish regulatory assets for stranded costs related Total Property, Plant and Equipment 17,679 17,862 to the electric Customer Choice program and deferred Less Accumulated Depreciation and Depletion environmental expenditures.

Electric Utility Generation (3,231) (3,046)

Distribution (2,108) (2,051) GAS PRODUCTION Transmission (1) - (327) We follow the successful efforts method of accounting for Total Electric Utility (5,339) (5,424) investments in gas properties. Under this method of accounting, Gas Utility all property acquisition costs and costs of exploratory and Distribution (798) (756) development wells are capitalized when incurred, pending Storage (102) (99) determination of whether the well has found proved reserves.

Other (432) (457) If an exploratory well has not found proved reserves, the costs Total Gas Utility (1,332) (1,312) of drilling the well are expensed. The costs of development wells Energy Services are capitalized, whether productive or nonproductive. Geological Coal Based Fuels (219) (163) and geophysical costs on exploratory prospects and the costs of On-Site Energy (42) 130) carrying and retaining unproved properties are expensed as incurred.

An impairment loss is recorded to the extent that capitalized costs Merchant Generation (20) (11) of unproved properties, on a property-by-property basis, are Other (2) 1')

considered not to be realizable. An impairment loss is recorded if Total Energy Services (283) (205) the net capitalized costs of proved gas properties exceed the Other non-regulated and other (401) (379) aggregate related undiscounted future net revenues. Depreciation, Total Accumulated Depreciation depletion and amortization of proved gas properties are determined and Depletion (7,355) (7,320) using the units-of-production method.

Net Property, Plant and Equipment S 10,324 $ 10,542 (11Represents the operations of ITC that were sold inFebruary 2003.

LONG-LIVED ASSETS shares. We account for stock awards under the plan under the recognition and measurement principles of Accounting Principles Long-lived assets that we own are reviewed for impairment Board (APB) Opinion No. 25, "Accounting for Stock Issued to whenever events or changes in circumstances indicate the carrying Employees." No compensation cost related to stock options is amount of an asset may not be recoverable. If the carrying amount reflected in net income, as all options granted had an exercise of the asset exceeds the expected future cash flows generated by price equal to the market value of the underlying common stock on the asset, an impairment loss isrecognized resulting inthe asset the date of grant. The recognition provisions under SFAS No. 123, being written down to its estimated fair value. Assets to be 'Accounting for Stock-Based Compensation," require the recording disposed of are reported at the lower of the carrying amount or of compensation expense for stock options equal to their fair value fair value less cost to sell. at date of grant as determined using an option pricing model. The following table illustrates the effect on net income and eamings SOFTWARE COSTS per share if we had recorded compensation expense for options We capitalize the costs associated with computer software we granted under the fair value recognition provisions of SFAS No. 123.

develop or obtain for use in our business. We amortize computer (inMillions, exceptpershare amounts) 2003 2002 2001 software costs on a straight-line basis over expected periods of Net Income As Reported $ 521 $ 632 $ 332 benefit once the installed software isready for its intended use.

Less: Total Stock-based Expense (1) (7) (7) (9)

Pro Forma Net Income $ 514 $ 625 $ 323 EXCISE AND SALES TAXES Earnings Per Share We record the billing of excise and sales taxes as receivables with Basic - as reported $ 3.11 $ 3.85 $ 2.17 an offsetting payable to the applicable taxing authority, with no Basic - pro forma S 3.06 $ 3.81 $ 2.11 impact on the statement of operations. Diluted -as reported S 3.09 $ 3.83 $ 2.16 Diluted - pro forma S 3.05 $ 3.79 $ 2.10 DEFERRED DEBT COSTS (1)Expense determined using a Black-Scholes based option pricing model.

The costs related to the issuance of long-term debt are deferred and amortized over the life of each debt issue. Inaccordance with INVESTMENTS IN DEBT AND EQUITY SECURITIES MPSC regulations applicable to our electric and gas utilities, the We generally classify investments in debt and equity securities unamortized discount premium and expense related to debt redeemed as either trading or available-for-sale and have recorded such with a refinancing are amortized over the life of the replacement investments at market value with unrealized gains or losses included issue. Discount, premium and expense on early redemptions of debt inthe Consolidated Statement of Operations or inother comprehensive associated with non-regulated operations are charged to earnings. income or loss, respectively. Changes inthe fair value of certain other investments are recorded as adjustments to regulatory INSURED AND UNINSURED RISKS assets or liabilities.

We have a comprehensive insurance program in place to provide coverage for various types of risks. Our insurance policies cover GAINS FROM SALE OF INTEREST IN SYNTHETIC risk of loss from various events, including catastrophic storms, FUEL FACILITIES general liability, workers' compensation, auto liability, property and When we sell an interest in a synfuel facility, we recognize the directors and officers liability. gain from such sale under the installment method of accounting.

Gain recognition isdependent on the synfuel production qualifying Under our risk management policy, we self-insure portions of certain for Section 29 tax credits. Accordingly, we have deferred gains risks up to specified limits, depending on the type of exposure.

totaling $311 million and $161 million as of December 31, 2003 We periodically review our insurance coverages and during 2003, and 2002, respectively.

we reviewed our process for estimating and recognizing reserves for self-insured risks. As a result of this review, we revised the process for estimating liabilities under our self-insured layers to INVESTMENT IN PLUG POWER include an actuarially determined estimate of "incurred but not In1997, we invested in Plug Power Inc., a company that designs reported IIBNR) claims. This revision resulted in the recording of and develops on-site electric fuel cell power generation systems.

an additional liability and reduced earnings in 2003 by approximately Since Plug Power is considered a development stage company, I

$15 million, primarily related to general liability and workers' generally accepted accounting principles required us to record compensation exposures. We intend to have an actuarially gains and losses from Plug Power stock issuances as an adjustment determined estimate of our IBNR liability prepared annually and to equity. Prior to November 2003 we accounted for our investment will adjust the related reserve as appropriate. in Plug Power Inc. under the equity method of accounting. We did o not participate in Plug Power's secondary stock offering in November STOCK-BASED COMPENSATION 2003 and as of December 31, 2003 we own approximately 19% of Plug Power's common stock. We have determined that we do not T We have a stock-based employee compensation plan, which is have the ability to exercise significant influence over the operating described in Note 15. The plan permits the awarding of various or financial policies of Plug Power. Accordingly, we began stock awards, including options, restricted stock and performance prospective application of the cost method of accounting for our I.

i II: I II~ I - -lj

investment in Plug Power, effective November 2003. We record SFAS No. 133 establishes accounting and reporting standards for our investment at market value and account for unrealized gains derivative instruments and for hedging activities. SFAS No. 133 and losses in other comprehensive income or loss. required that as of the date of initial adoption, the difference between the fair value of derivative instruments and the previous CONSOLIDATED STATEMENT OF CASH FLOWS carrying amount of those derivatives be reported in net income or other comprehensive income as the cumulative effect of a change We consider investments purchased with a maturity of three months in accounting principle. The cumulative effect of adopting SFAS or less to be cash equivalents. Cash contractually designated for No. 133 on January 1,2001 was an increase in net income of $3 debt service isclassified as restricted cash. million and an increase in other comprehensive loss of $42 million.

(inMillions) 203 2002 2001 Effective July 1,2003, we adopted SFAS No. 149, "Amendment of Changes inAssets and - Statement 133 on Derivative Instruments and Hedging Activities."

Liabilities, Exclusive of Changes Shown Separately The statement amends and clarifies financial accounting and Accounts receivable, net $ (113) $ (157) $ 17 reporting for derivative instruments, including derivative instruments Accrued unbilled receivables (20) (54) (19) embedded in other contracts and for hedging activities. Our financial Accrued gas cost recovery revenue 29 (5 (14) statements were not impacted by the adoption of SFAS No. 149.

Inventories (61) I(7) (76) InAugust 2003, the EITF released Issue No. 03-11, which provides Accounts payable (321) 8 (105) guidance on whether to report realized gains or losses on a gross Income taxes payable 135 (86) (102 or net basis on physically settled derivative contracts not held General taxes for trading purposes. The new guidance was implemented in (12) (36) 2 Risk management and trading activities 127 69 (80) the fourth quarter of 2003 and had an immaterial effect on our Pension contributions (222) (35) (35) financial statements.

Postretirement obligation 93 58 27 Other 138 4 (86) See Note 12 - Financial and Other Derivative Instruments for 73 $ (169) $ (527) additional information.

Other cash and non-cash investing and financing activities for the ENERGY TRADING CONTRACTS years ended December 31 were as follnInw Under EITF Issue No. 98-10, companies were required to use (inMillions) 2003 2002 2001 mark-to-market accounting for contracts utilized in energy trading Supplementary Cash Flow activities. EITF Issue No. 98-10 was rescinded in October 2002, Information and energy trading contracts must now be reviewed to determine if Interest paid they meet the definition of a derivative under SFAS No. 133. SFAS (excluding interest capitalized) S 552 $ 551 $ 409 No. 133 requires all derivatives to be recognized in the statement Income taxes paid 31 167 45 of financial position as either assets or liabilities measured at their Noncash Investing and fair value and sets forth conditions in which a derivative instrument Financing Activities may be designated and recognized as a hedge. SFAS No. 133 also Exchange of debt : 100 $ - $ - requires that changes inthe fair value of derivatives be recognized Notes received from sale of in earnings unless specific hedge accounting criteria are met.

synfuel projects 238 217 - Energy trading contracts not meeting the definition of a derivative Issuance of equity-linked are accounted for under settlement accounting, effective October securities - 21 - 25, 2002 for new contracts and effective January 1,2003 for Issuance of common stock for existing contracts. Derivative contracts are only marked to market acquisition of MCN Energy - - 1,060 to the extent that markets are considered highly liquid where unting policies impacting our objective, transparent prices can be obtained. Unrealized See the following notes for other acco gains and losses are fully reserved for transactions that do not financial statements.

meet this criteria.

Note Title Additionally, inventory utilized in energy trading activities accounted 4 Regulatory Matters for under the fair value method of accounting as prescribed by 7 Income Taxes Accounting Research Bulletin (ARB) No. 43 isno longer permitted.

12 Financial and Other Derivative Instruments DTE Energy's Energy Marketing & Trading segment uses gas 14 Retirement Benefits and Trusteed Assets inventory in its trading operations and switched to the average cost inventory accounting method inJanuary 2003.

NOTE 2 - New Accounting Pronouncements--

Effective January 1,2003, we applied EITF Issue 02-03 which DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES rescinded EITF Issue 98-10. As a result of discontinuing the appli-cation of EITF Issue No. 98-10 to energy contracts and ARB No. 43 Effective January 1,2001, we adopted SEAS No. 133, Accounting to gas inventory, we recorded a cumulative effect of accounting for Derivative Instruments and Hedging Activities,' as amended.

iI, ' I

change that reduced net income for the first quarter of 2003 by over the useful life of the related asset. Upon settlement of the

$16 million (net of taxes of $9million.) liability, an entity settles the obligation for its recorded amount or incurs a gain or loss upon settlement.-

GOODWILL AND OTHER INTANGIBLE ASSETS We have identified a legal retirement obligation for the Effective January 1,2002, we adopted SFAS No. 142, "Goodwill decommissioning costs for our Fermi 1and 2 nuclear plants.

and Other Intangible Assets," which addresses the financial To a lesser extent, we have retirement obligations for our accounting and reporting standards for the acquisition of intangible synthetic fuel operations, gas production facilities, asphalt plant, assets outside of a business combination and for goodwill and gas gathering facilities and various'other operations. As to other intangible assets subsequent to their acquisition. This regulated operations, we believe that adoption of SFAS No. 143 accounting standard requires that goodwill be separately disclosed results primarily intiming differences in the recognition of legal from other intangible assets inthe balance sheet. Additionally asset retirement costs that we are currently recovering in rates under this statement, goodwill isno longer amortized, but must be and are deferring such differences under SFAS No. 71, reviewed at least annually for impairment. The provisions of this "Accounting for the Effects of Certain Types of Regulation."

accounting standard also required the completion of a transitional impairment test within six months of adoption, with any impairment As aresult of adopting SFAS No. 143 on January 1,2003, we .

treated as a cumulative effect of achange in accounting principle. recorded a plant asset of $306 million with offsetting accumulated We completed the annual goodwill impairment test and have depreciation of $106 million, a retirement obligation liability of determined that no impairment exists. $815 million and reversed previously recognized obligations of

$377 million, principally nuclear decommissioning liabilities. We Inaccordance with SFAS No. 142, we discontinued the amortization also recorded a cumulative effect amount related to regulated of goodwill effective January 1,2002. A reconciliation of previously operations as a regulatory asset of $221 million, and a cumulative reported 2001 net income and earnings per share to the amounts effect charge against earnings of $11 million (net of tax of $6million) adjusted for the exclusion of goodwill amortization follows: for 2003.

Year Ended December 31, 2001 If a reasonable estimate of fair value cannot be made inthe period Basic Diluted the asset retirement obligation isincurred, such as assets with an (InMillions, except Net Earnings Earnings indeterminate life, the liability isto be recognized when a reasonable per share amounts) Income Per Share Per Share estimate of fair value can be made. Generally, distribution assets As reported S 332 $ 2.17 $ 216 have an indeterminate life, retirement cash flows cannot be Add: Goodwill amortization 31 .20 .20 determined and there isa low probability of retirement, therefore As adjusted $ 363 $ 2.37 $ 2.36 no liability has been recorded for these assets.

Inconnection with the adoption of SFAS No. 142, we also The pro forma effect on earnings had SFAS No. 143 been adopted reassessed the useful lives and the classification of identifiable for all periods presented would decrease reported net income and intangible assets and determined that they continue to be basic and diluted earnings per share as follows:

appropriate. Our intangible assets consist primarily of software and are subject to amortization. Intangible assets amortization (inMillions]

expense was $40 million in2003, $46 million in 2002 and $48 million Net Basic and Diluted in 2001. There were no material acquisitions of intangible assets Year Income Earnings per Share during 2003 and 2002. The gross carrying amount and accumulated 2003 $ 4.8 $ .03 amortization of intangible assets at December 31, 2003 were $537 2002 $ 4.8 $ .03 million and $303 million, respectively. The gross carrying amount' 2001 E$ 4.2 $ .03 and accumulated amortization of intangible assets at December 31, 2002 were $526 million and $317 million, respectively. The pro forma effect of the asset retirement obligation had SFAS Amortization expense of intangible assets isestimated to be No. 143 been adopted for all periods presented would increase

$40 million annually for 2004 through 2008. reported liabilities by $815 miillion and $807 million as of December 31, 2002 and 2001, respectively.

ASSET RETIREMENT OBLIGATIONS A reconciliation of the asset retirement obligation for 2003 follows:

On January 1,2003, we adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," which requires the fair value of an (inMillions) asset retirement obligation be recognized in the period inwhich it Asset retirement obligations at January 1,2003 $ 815 isincurred. Itapplies to legal obligations associated with the Accretion o 55 Liabilities settled (4) retirement of long-lived assets resulting from the acquisition, construction, development and (or) the normal operation of a Asset retirement obligations at December 31, 2003 $ 866 long-lived asset:f When a new liability is recorded, an entity will capitalize the costs of the liability by increasing the carrying SFAS No. 143 also requires the quantification of the estimated amount of the related long-lived asset. The liability isaccreted to cost of removal obligations, arising from other than legal obligations, its present value each period, and the capitalized cost isdepreciated which have been accrued through depreciation charges. At 1'

December 31, 2002, we reclassified approximately $7:29 million of respective parent companies. As of December 31, 2003, the trusts previously accrued asset removal costs related to our regulated have $280 million of preferred securities outstanding. The sole operations, which had been previously netted against accumulated assets of the trusts are debentures of their parent companies with depreciation, to an asset removal cost liability. At December 31, terms similar to those of the related preferred securities.

2003, we reclassified approximately $655 million of tl hese accrued asset removal obligations to regulatory liabilities. Prior to the application of FIN 46-R, we consolidated these trusts.

However, pursuant to the provisions of FIN 46-R, these trusts meet EXIT AND DISPOSAL ACTIVITIES the definition of special purpose entities. Upon applying the provisions of FIN 46-R to these trusts as of December 31, 2003, Effective January 1,2003, we adopted SFAS No. 146, "Accounting we have determined that the trusts are variable interest entities, for Costs Associated with Exit or DisposalActivities," which - as our common equity investment isconsidered not at risk, and requires that the liability for costs associated with exi t or disposal we are not the primary beneficiaries of the trusts. Accordingly, activities be recognized when incurred, rather than atthe date of a we have deconsolidated these trusts as of December 31, 2003 commitment to an exit or disposal plan. The adoption of this , and our balance sheet was modified to reflect Investments in statement had no impact on our consolidated financiaI statements. Unconsolidated Subsidiaries (included in Other Investments) of

- approximately $9million, representing our common equity investment CONSOLIDATION OF VARIABLE INTEREST ElNTITIES in the trusts, and Long-Term Debt of approximately $289 million, representing our obligations related to the trust debentures.

InJanuary 2003, FASB Interpretation No. (FIN) 46, "Ccmnsolidation of Variable Interest Entities, an Interpretation of ARBXNo. 51," was As permitted under FIN 46-R, we have deconsolidated the trusts in issued and requires an investor with a majority of the variable . prior periods to be consistent with the current year's presentation.

interests (primary beneficiary) in avariable interest erItity to The adoption of FIN 46-R did not result in a cumulative effect of an consolidate the assets, liabilities and results of opera, tions of the accounting change adjustment.

entity. A variable interest entity isan entity inwhich the equity investors do not have controlling interests, the equity investment We continue to evaluate all of our cost and equity method at risk isinsufficient to finance the entity's activities vvithout - investments created prior to February 1,2003 to determine receiving additional subordinated financial support froimother whether those entities are variable interest entities that require parties, or equity investors do not share proportionally ,in gains or consolidation. The effects of adopting the provisions of FIN 46-R losses. FIN 46 was applicable (i)immediately for all vvariable . to those entities are not expected to have a material effect on our interest entities created after January 31, 2003; or (ii) in the first financial statements.

fiscal year or interim period beginning after June 15, i?003 for variable interest entities created before February 1,2(003. FINANCIAL INSTRUMENTS WITH CHARACTERISTICS InOctober 2003, the FASB issued Staff Position No. FlIN46-6, - OF LIABILITIES AND EQUITY-which allowed for the deferral of the effective date for applying Effective July 1,2003, we adopted SFAS No. 150, "Accounting for the provisions of Interpretation No. 46 for all interests invariable Certain Financial Instruments with Characteristics of Both interest entities created before February 1,2003, until the end of Liabilites and Equity," which establishes standards for classifying the first interim or annual period ending after Decemb her 15, 2003. and measuring as liabilities certain financial instruments that embody obligations of the issuer and have characteristics of both InDecember 2003, the FASB issued FIN 46-Revised (FIN46-R) liabilities and equity.

which clarified and replaced FIN 46. FIN 46-R again dleferred the adoption of its provisions until periods ending after March 15. The adoption of SFAS No. 150 did not impact our financial statements.

2004, however, application is required for periods end ed after December 15, 2003 for public entities that have intere!sts i NOTE 3 - Acquisitions and Dispositions special-purpose entities. FIN 46-R defines special pur -pose N T custosadDsoiin entities as any entity whose activities are primarily related to securitizations or other forms of asset-backed financirigs or ACQUISITION OF MCN ENERGY single-lessee leasing arrangements. Inaddition, FIN 46-Rprovides On May 31, 2001, DTE Energy completed the acquisition of MCN for further scope exceptions, including an exception fcir entities Energy by acquiring all of its outstanding shares of common stock that are deemed to be a business, provided certain cond'itions are met. for a combination of cash and shares of our common stock. See Note 8- Common Stock and Earnings per Share for additional As of December 31, 2003, we have determined that we Ihave interests information. We purchased the outstanding common stock of in various entities that would not qualify for the defer ral provisions MCN Energy for $2.3 billion and assumed existing MCN Energy of FIN 46-R. As a result, we have adopted the provisi ons of FIN debt and preferred securities of $1.5 billion.

46-R as of December 31, 2003 relative to our interests sin these-special purpose entities and have deferred the applicEation of the We accounted for the acquisition using the purchase method and provisions of FIN 46-R until March 31, 2004 for all other entities. accordingly allocated the purchase price to the fair value of the assets acquired and liabilities assumed. The excess of the purchase We have interests intwo trusts formed for the sole paerpose of price over the fair value of net assets acquired totaled $2.1 billion issuing preferred securities and lending the gross pro(:eeds to their and was classified as goodwill. We began amortizing goodwill on

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June 1,2001, on a straight-line basis using a 40-year life. In Energy's decision to sell ITC is consistent with our strategic view accordance with the adoption of SFAS No. 142 on January 1,2002, that maximization of shareholder value and high levels of customer the amortization of goodwill ceased, and goodwill istested for service are best achieved with assets we own, operate and exercise impairment on an annual basis. significant control. As provided in FERC regulations, Detroit Edison continues to have fair and open access to Michigan's electric The following unaudited pro forma summary presents information transmission network. The ITC electric transmission system continues about the company as if the acquisition became effective at the to be operated by the Midwest Independent System Operator, a beginning of the respective periods. The pro forma amounts regional transmission operator. ITC received FERC approval to cap include the impact of certain adjustments, such as acquiring the transmission rates charged to Detroit Edison's customers at current operations of MCN Energy and issuing $1.35 billion of debt and 29 levels until December 31, 2004. Thereafter, rates are subject to million shares of common stock to finance the acquisition. The pro adjustment by the FERC.

forma amounts do not reflect the benefits from synergies we are receiving as a result of combining operations, do not reflect the SFAS No. 144, "Accounting for the Impairment or Disposal of actual results that would have occurred had the companies been Long-Lived Assets," provides that the results of operations of a combined for the periods presented, and are not necessarily component of an entity that has been disposed of should be indicative of future results of operations of the combined companies. reported as adiscontinued operation when the operations and cash flows of the component have been eliminated from the Ya Pro Forma ongoing operations of the entity and the entity will not have Year Ended December31 any significant continuing involvement in the operations of the (inMillions, except per share amounts) 2001 component after the disposal transaction. As a result, we have Operating revenues $ 9,393 reported the operations of ITC as a discontinued operation as Income from continuing operations $ 514 shown inthe following table:

Net income $ 537 (inMillions) 2003 (3i 2002 2001 (4)

Basic earnings per share: Revenues l) S 21 S 138 $ 64 Income from continuing operations $ 3.10 Expenses(2) 13 67 35 Total $ 3.25 Operating income 8 71 29 Income taxes 3 25 9 Diluted earnings per share: Income from discontinuedoperations $ 5$ 46 $ 20 Income from continuing operations $ 3.08 (1 Includes intercompany revenues of $18 million for 2003, $118 million for2002 Total $ 3.23 and $60 million for 2001.

(21Excludes general corporate overhead costs that were previously allocated We incurred merger related costs of $27 million ($18 million, net of to ITC.-

tax) and restructuring costs of $241 million ($157 million, net of (31 Represents activity from January 1,2003 through February 28, 2003 when tax) during 2001. Merger related charges represent systems ITC was sold.

integration, relocation, legal, accounting and consulting costs. (4)Represents activity from June 1,2001 through December 31, 2001.

Restructuring charges were primarily associated with a work force reduction plan. The plan included early retirement incentives and Prior to May 31, 2001, Detroit Edison owned and operated the voluntary separation agreements for 1,186 employees, primarily in transmission assets of ITC, which were vertically integrated with overlapping corporate support areas. Approximately $53 million of its other operations. Accordingly, revenues, expenses and cash the merger and restructuring charges were paid as of December flows associated with these transmission assets were included 31, 2001 and remaining benefit payments have been or will be with the Energy Distribution - Regulated Power Distribution segment paid from retirement plans. and were not separately identifiable. Effective June 1,2001, the transmission assets of ITC were transferred to DTE Corporate and DISPOSITION OF INTERNATIONAL TRANSMISSION its revenues, expenses and cash flows were separately monitored COMPANY- DISCONTINUED OPERATION to measure its financial and operating performance. Accordingly, the presentation of discontinued operations in the consolidated InDecember 2002, we entered into a definitive agreement with statement of operations reflects the results of ITC after May 31, 2001.

affiliates of Kohlberg Kravis Roberts & Co. and Trimaran Capital Partners, LLC providing for the sale of ITC for approximately ITC had net property of $388 million at December 31, 2002. In

$610 million in cash. The sale closed in February 2003 following conjunction with the sale of ITC, approximately $44 million of approval of the transaction by the FERC and the resolution of all goodwill allocated to this segment was written off and reduced.

other contingencies. The sale generated an after tax gain of $63 the net of tax gain.

million, which was net of transaction costs and the portion of the gain that was refundable to customers. DISPOSITION OF DETROIT EDISON'S STEAM The FERC had encouraged integrated electric utilities to transfer HEATING BUSINESS operating control of their transmission facilities to independent InJanuary 2003, we sold Detroit Edison's steam heating business operators or sell the facilities to an independent company. DTE to Thermal Ventures 11, LLP. This disposition isconsistent with DTE I I I I I

Energy's strategy of divestiture of non-strategic assets. Due to the and expense in non-regulated businesses. Continued applicability continuing involvement of Detroit Edison in the steam heating of SFAS No. 71 requires that rates be designed to recover specific business, including the commitment to purchase $150 million in costs of providing regulated services and be charged to and collected steam for resale through 2008, fund certain capital improvements from customers. Future regulatory changes or changes in the and guarantee the buyer's credit facility, we recorded a net of tax competitive environment could result in the company discontinuing loss of approximately $14 million in 2003. As a result of Detroit the application of SFAS No. 71 for some or all of its businesses Edison's continuing involvement, this transaction is not considered and require the write-off of the portion of any regulatory asset or a sale for accounting purposes. The steam heating business had liability that was no longer probable of recovery through regulated assets of $6million at December 31, 2002, and had net losses of rates. Management believes that currently available facts support the

$12 million in 2002 and net income of $3million in2001. See Note continued application of SFAS No. 71 to Detroit Edison and MichCon.

13 - Commitments and Contingencies.

The following are the balances of the regulatory assets and liabilities at December31:

NOTE 4 - Regulatory Matters (inMillions) 2003 2002 REGULATION Assets Detroit Edison and MichCon are subject to the regulatory jurisdiction Securitized regulatory assets $ 1,527 $ 1,613 of the MPSC, which issues orders pertaining to retail rates, recovery Recoverable income taxes related to securitized regulatory assets $ 837 $ 884 of certain costs, including the costs of generating facilities and regulatory assets, conditions of service, accounting and operating- Recoverable minimum pension liability 585 related matters. Detroit Edison is also regulated by the FERC with Asset retirement obligation 192 -

respect to financing authorization and wholesale electric activities. Other recoverable income taxes 114 118 Recoverable costs under PA 141 In 1998, based on MPSC Orders, the Power Generation business of Net stranded costs 68 10 Detroit Edison started transitioning to market-based rates with the Deferred Clean Air Act expenditures 54 11 start of a customer choice program. Incompliance with EITF Issue Midwest Independent System No. 97-4, "Deregulation of the Pricing of Electricity", we ceased Operator charges 21 9 application of SFAS No. 71, 'Accounting for the Effects of Certain Transmission integration costs 10 19 Types of Regulation", for the generation business in 1998. Since Electric Choice implementation costs 84 76 that time, there have been significant legislative and regulatory Enhanced security costs 6 -

changes in Michigan that have resulted in our generation business Unamortized loss on reacquired debt 60 36 being fully regulated with cost-based ratemaking. Deferred environmental costs 29 29 Accrued gas cost recovery 19 22 InJune 2000, the Customer Choice and Electric Reliability Act (PA 141) Other 3 5 was enacted into law providing the regulatory framework to 2,082 1,219 maintain cost-based rates for retail customers and ensuring the Less amount included incurrent assets (19) 122) recovery of all amounts of generation-related stranded costs from

$ 2,063 $ 1,197 choice customers. Subsequent MPSC orders developed a cost-based Liabilities methodology to determine the amount of our net stranded costs to be recovered from choice customers. Since the rates for retail Asset removal costs $ 655 $ -

customers and the recovery of net stranded costs that are set by Excess securitization savings 14 35 the regulator recover Detroit Edison's generation costs and are Customer Refund - 1997 Storm 2 2 billed and recovered from full service and choice customers, the Refundable income taxes 146 142 criteria of SFAS No. 71 are satisfied. Inaddition, we believe we Accrued GCR potential disallowance 26 -

have both the legislative and regulatory authority to defer regula- Other 3 3 tory costs and to begin recovery of such costs starting in 2004 846 182 after the PA 141 mandated rate freeze expires. The SEC had no Less amount included in current and objection to Detroit Edison resuming application of SFAS No. 71 other liabilities (29) (3) for its generation business in the fourth quarter of 2002. Detroit $ 817 $ 179 Edison recorded $15 million of additional regulatory assets for the equity component of Allowance for Funds Used During Construction Securitizedregulatoryassets-The net book balance of the Fermi 2 and costs related to reacquired debt that was refinanced with nuclear plant was written off in 1998 and an equivalent regulatory lower cost debt. Prior period financial statements were not restated asset was established. In 2001, the Fermi 2 regulatory asset and due to the immaterial effect of retroactively applying SFAS No. 71 certain other regulatory assets were securitized pursuant to Public to Detroit Edison's generation business. Act (PA) 142 and an MPSC Order. A non-bypassable securitization bond surcharge recovers the securitized regulatory asset over a REGULATORY ASSETS AND LIABILITIES fourteen-year period ending in 2015.

SFAS No. 71 requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as revenue II ' 'I

Recoverable income taxes related to securitized regulatory assets A deferred return computed using MichCon's short-term borrowing

- Receivable for the recovery of income taxes to be paid on the rate isalso being accrued on the under-recovered balances.

non-bypassable securitization bond surcharge. A non-bypassable securitization tax surcharge recovers the income tax. Assetremoval costs-The amount collected from customers for the funding of future asset removal activities. - -

Recoverable minimum pension liability- An additional minimum pension liability was recorded in 2002 and 2003 (Note 14). The Excess securitization savings- Savings associated with the 2001 traditional rate setting process allows for the recovery of pension securitization of Fermi 2 and other costs are refundable to Detroit costs as measured by generally accepted accounting principles. Edison's customers.

Accordingly, the minimum pension liability associated with regulated operations is recoverable. Customer Refund- 1997Storm-The over collection of the 1997 storm costs, which are refundable to Detroit Edison customers Asset retirement obligation - Asset retirement obligations were after January 1,2004.

recorded pursuant to adoption of SFAS No. 143 in 2003. These obligations are primarily for Fermi 2 decommissioning costs that Refundable income taxes- Income taxes refundable to MichCon's are recovered in rates. customers representing the difference in property-related deferred income taxes payable and amounts recognized pursuant to MPSC Other recoverable income taxes- Income taxes receivable from authorization.

Detroit Edison's customers representing the difference in property-related deferred income taxes payable and amounts previously Accrued GCR potential disallowance'- A March 2003 MPSC Order reflected in Detroit Edison's rates. in MichCon's 2002 GCR plan case required MichCon to reduce revenues in the calculation of its 2002 GCR expense.

Net stranded costs- PA 141 permits, after MPSC authorization, the full recovery of fixed cost deficiency associated with the electric ELECTRIC TRANSITIONAL RATE PLAN Customer Choice program. Net stranded costs occur when fixed cost related revenues do not cover the fixed cost revenue requirements. Rate Request- InJune 2003, Detroit Edison filed an application with the MPSC requesting a change in'retail electric rates, Deferred Clean AirAct expenditures - PA 141 permits, after resumption of the Power Supply Cost Recovery (PSCR) mechanism, MPSC authorization, the recovery of and a return on Clean Air and recovery of net stranded costs. The application requested a Act expenditures. base rate increase for both full service and electric Customer Choice customers totaling $416 million annually (approximately Midwest Independent System Operator charges - PA 141 12% increase) in 2006, with a three year phase-in starting in 2004 permits, after MPSC authorization, the recovery of charges from a as the caps on customer rates expire, as subsequently discussed.

regional transmission operator such as the Midwest Independent Detroit Edison proposed that the $416 million increase be allocated System Operator. between full service customers ($265 million) and electric Customer Choice customers ($151 million]. In November 2003, Transmission integration costs - PA 141 permits, after MPSC Detroit Edison increased its original rate request by $11 million to authorization, the recovery of transmission integration costs. $427 million. The rate request also seeks a five-year surcharge totaling $109 million from both full service and electric Customer Electric Choice implementation costs - PA 141 permits, after Choice customers to recover certain deferred regulatory asset MPSC authorization, the recoverability of costs incurred balances, including electric Customer Choice program implementation associated with the implementation of the electric Customer costs, return on and of clean air investments made prior to inclusion Choice program. A deferred return of 7%isalso being accrued in base rates and net stranded costs for years prior to 2004.

on the unrecovered balance. Detroit Edison requested authority to increase rates on an interim basis by $299 million annually to all customers not subject to a rate Enhancedsecuritycosts- PA 141 permits, after MPSC authorization, cap. PA 141 became effective in June 2000 and contains provisions the recovery of enhanced homeland security costs for an electric freezing rates through 2003 and preventing rate increases for generating facility. residential customers through 2005 and for small commercial and industrial customers through 2004. Detroit Edison requested the Unamortized loss on reacquired debt- The unamortized discount, MPSC act on our interim request in order to be effective January 1, premium and expense related to debt redeemed with a refinancing 2004. Concurrent with the issuance of an order for interim rate relief, are deferred, amortized and recovered over the life of the Detroit Edison requested reinstatement of the PSCR mechanism.

replacement issue. The PSCR mechanism allows Detroit Edison to recover through rates its fuel and purchased power expenses' The PSCR was Deferred environmental costs- The MPSC approved recovery suspended by the MPSC following passage of PA 141. Detroit of costs for investigation and remediation incurred at former Edison also proposed that base' rates for the customer classes still manufactured gas plant sites. subject to rate caps in 2004 and 2005 remain frozen and not be subject to the PSCR mechanism until the caps expire.

Accrued gas cost recovery- The amount of under-recovered gas costs incurred by MichCon recoverable through the GCR mechanism.

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A summary of the total rate increase request follows: charge previously in effect. However, the MPSC order will allow Detroit Edison to increase base rates for customers still subject to (inMillions) the cap in an equal and offsetting amount with the change in the Base Rate Revenue Deficiency $ 553 PSCR factor to maintain the total capped rate levels currently in PSCR Savings/Choice Mitigation (126) effect for these customers.

Base Rate Increase 427 Regulatory Asset Recovery Surcharge 109 Although the base rate increase totaled $248 million, the interim Total $ 536 order isonly designed to result in an increase in 2004 revenues of Phase in ByYear $71 million. This lower amount isa result of the rate caps, the 2004 $ 299 February 21, 2004 effective date and the PSCR adjustment.

2005 57 Amounts collected will be subject to refund pending afinal order 2006 180 in this rate case.

Total $ :536 As part of the interim order, the MPSC approved Detroit Edison's request to recover pension and healthcare expenses included in the The filing also requests a permanent capital structure based on rate filing. The recovery isconditioned on Detroit Edison making 50% debt and 50% equity, and a proposed return on equity (ROE) minimum annual prorated pension contributions equal to the of 11.5%. Detroit Edison isalso proposing a symmetrical ROE amount of expense reflected in rates during the period that the sharing mechanism, which will apply to full service and electric - authorized interim rates are in effect. Detroit Edison has agreed to Customer Choice customers whose rates are no longer capped comply with this requirement through the interim period until a under PA 141. The sharing proposal would provide that shareholders final order is issued in this case. Additionally, the MPSC interim retain all earnings within a 1%band above and below the authorized order requires Detroit Edison to continue funding the Low Income ROE. If the actual ROE falls outside of the band, customers would Energy Efficiency Fund at $40 million annually.

share between 20% and 80% of the excess or shortfall of earnings, depending on actual ROE. The ROE sharing mechanism would be The MPSC deferred addressing other items in the rate request, effective for the calendar year inwhich a final order is received including a surcharge to recover regulatory assets, until a final rate in this case. order isissued which isexpected inthe third quarter of 2004. We cannot predict the amount of final rate relief that will be granted As previously discussed, Detroit Edison requested that its PSCR by the MPSC.

clause remain suspended and that implementation of a new PSCR factor not begin until the date of the MPSC order authorizing adequate ELECTRIC INDUSTRY RESTRUCTURING and compensatory relief. Detroit Edison also proposed an adjustment whereby the revenues from the sale of excess capacity and Electric Rates, Customer Choice and Stranded Costs - PA 141 off-system energy would be used to mitigate the effect of stranded provided Detroit Edison with the right to recover net stranded costs. InDecember 2003, the MPSC issued an order that reinstated costs, codified and established January 1,2002 as the date for full the PSCR clause on January 1,2004 and did not rule on the mitigation implementation of the MPSC's existing electric Customer Choice adjustment proposed by Detroit Edison. Detroit Edison has filed an program, and required the MPSC to reduce residential electric appeal of this order with the Michigan Court of Appeals. rates by 5%. At that time, PA 142 also became effective. PA 142 provided for the recovery through securitization of qualified costs" MPSC Interim Rate Order- On February 20, 2004, the MPSC which consist of an electric utility's regulatory assets, plus various issued an order for interim rate relief. The order authorized an costs associated with, or resulting from, the establishment of a interim increase in base rates, a transition charge for customers competitive electric market and the issuance of securitization bonds.

participating in the electric Customer Choice program and a new PSCR factor. Acting pursuant to PA 141, in an order issued inJune 2000, the MPSC reduced Detroit Edison's residential electric rates by 5%and' The interim base rate increase totaled $248 million annually, effective imposed a rate freeze for all classes of customers through 2003.

February 21, 2004, and isapplicable to all customers not subject to InApril 2001, commercial and industrial rates were lowered by 5%

the rate cap. The increase will be allocated to both full service 0 - as a result of savings derived from the issuance of securitization customers ($240 million) and electric Customer Choice customers bonds in March 2001, as subsequently discussed.

($8 million). However, because of the rate caps under PA 141, not all of the increase will be recognized in 2004. Additionally, Certain costs may be deferred and recovered once rates can be the MPSC terminated certain transition credits and authorized a increased. This rate cap may be lifted when certain market test uniform 4 mills per kWh transition charge to Choice customers provisions are met, specifically, when an electric utility has no which is designed to result in $30 million in revenues, based on an more than 30% of generation capacity in its relevant market, with estimated 7,565 gWh level of Choice sales volumes. The MPSC consideration for capacity needed to meet a utility's responsibility concluded that the implementation of transition charges, coupled to serve its retail customers. Statewide, multi-utility transmission with the termination of transition credits, will reduce the anticipated system improvements also are required. InMay 2003, Detroit volume of Choice sales resulting in an additional $30 million in Edison submitted filings with the MPSC regarding its compliance margins. The MPSC also authorized a PSCR factor for all customers, with the provisions of PA 141 related to market test and transmission a credit of 1.05 mills per kWh compared to the 2.04 mills per kWh system improvements. Detroit Edison entered into a settlement III ~~I. a '

agreement with interested parties, indicating that the market an estimate of the cumulative stranded costs as of that period. As power test provisions of PA 141 had been met. The MPSC a result of the MPSC July 2003 order and the related clarifying approved the settlement agreement on February 20, 2004. language, we recalculated net stranded costs for 2002 and 2003.

Our revised and ongoing calculations conclude that the $68 million As required by PA 141, the MPSC conducted a proceeding to develop of net stranded costs recorded as of December 31, 2003 isappropriate.

a methodology for calculating the net stranded costs associated with electric Customer Choice. Ina December 2001 order, the Securitization - Inan order issued in November 2000 and clarified MPSC determined that Detroit Edison could recover net stranded in January 2001, the MPSC approved the issuance of securitization costs associated with the fixed cost component of its electric bonds to recover qualified costs that include the unamortized generation operations. Specifically, there would be an annual investment in Fermi 2,costs of certain other regulatory assets, proceeding or true-up before the MPSC reconciling the receipt of Electric Choice implementation costs, costs of issuing securitization revenues associated with the fixed cost component of its generation bonds, and the costs of retiring securities with the proceeds of services to the revenue requirement for the fixed cost component securitization. The order permits the collection of these qualifying of those services, inclusive of an allowance for the cost of capital. costs from Detroit Edison's customers.

Any resulting shortfall in recovery, net of mitigation, would be considered a net stranded cost. The MPSC, in its December 2001 Detroit Edison formed The Detroit Edison Securitization Funding order, also determined that Detroit Edison had no net stranded LLC (Securitization LLC), awholly owned subsidiary, for the purpose costs in 2000 and consequently established a zero net stranded of securitizing its qualified costs. InMarch 2001, the Securitization cost transition charge for billing purposes in 2002. The MPSC LLC issued $1.75 billion of Securitization Bonds, and Detroit Edison authorized Detroit Edison to establish aregulatory asset to defer sold $1.75 billion of qualified costs to the Securitization LLC. The recovery of its incurred stranded costs, subject to review ina Securitization Bonds mature over a 14-year period and have an subsequent annual net stranded cost proceeding. The MPSC also annual average interest rate of 6.3% over the life of the bonds.

determined that Detroit Edison should provide a full and offsetting Detroit Edison used the proceeds to retire debt and equity in credit for the securitization and tax charges applied to electric approximately equal amounts. DTE Energy corporate likewise Customer Choice bills in 2002. Inaddition, the MPSC ordered an retired approximately 50% debt and 50% equity with the proceeds additional credit on bills equal to the 5%rate reduction realized by received as the sole shareholder of Detroit Edison; Detroit Edison full service customers. Both credits were to be funded from savings implemented a non-bypassable surcharge on its customer bills, derived from securitization. The December 2001 order, coupled effective in March 2001, for the purpose of collecting amounts with lower wholesale power prices, has encouraged additional sufficient to provide for the payment of interest and principal and customer participation in the electric Customer Choice program the payment of income tax on the additional revenue from the and has resulted in the loss of margins attributable to generation surcharge. As a result of securitization, Detroit Edison established services. InMay 2002, the MPSC denied Detroit Edison's request a regulatory asset for securitized costs including costs that had for rehearing and clarification of the December 2001 order. In previously been recorded in other regulatory asset accounts.

June 2002, Detroit Edison filed an appeal of the MPSC order at the Michigan Court of Appeals, challenging the legality of specific The Securitization LLC is independent of Detroit Edison, as is its aspects of the MPSC order. The Court of Appeals denied Detroit ownership of the qualified costs. Due to principles of consolidation, Edison's appeal. qualified costs sold by Detroit Edison to the Securitization LLC and the securitization bonds appear on the company's consolidated InMay 2002, Detroit Edison submitted its 2001 net stranded cost statement of financial position. The company makes no claim to filing with the MPSC. The filing provided refinements to the these assets. Ownership of such assets has vested in the MPSC Staff's calculation of net stranded costs that was adopted in Securitization LLC and been assigned to the trustee for the the December 2001 order, sought more timely recovery of net Securitization Bonds. Funds collected by Detroit Edison, acting in stranded costs, and addressed issues raised by the continuation of the capacity of a servicer for the Securitization LLC, are remitted to securitization offsets and rate reduction equalization credits. The the trustee for the Securitization Bonds. Neither the qualified filing supported that Detroit Edison had no net stranded costs in costs which were sold nor funds collected from Detroit Edison's 2000 and $13 million of recoverable net stranded costs attributable customers for the payment of costs related to the Securitization LLC

-.to electric Customer Choice in 2001. Inthe fourth quarter of 2002, and Securitization Bonds are available to Detroit Edison's creditors.

Detroit Edison recorded an estimated regulatory asset of $10 million for the 2001 net stranded costs based on the MPSC Staff's report. Low-Income EnergyAssistance Credit- InOctober 2003, Detroit InJuly 2003, the MPSC issued an order finding that Detroit Edison Edison filed an application with the MPSC to implement a had no net stranded costs in 2000 and 2001 and established a zero low-income energy assistance credit for residential electric net stranded cost transition charge for billing purposes in 2003. customers. The proposed 2.6 cent per kilowatthour credit isexpected Inaddition, this order clarified the inclusion of revenue discounts to assist many low-income customers who are experiencing difficulties in paying their electric bills due to poor economic calculation, but declined to rule on the proposed modifications to conditions in Detroit Edison's service area. Detroit Edison the method for determining net stranded costs. Detroit Edison filed proposed to fund the low-income energy assistance credit by a petition for rehearing of the July 2003 order, which the MPSC utilizing excess securitization savings currently being used to denied in December 2003. Detroit Edison has appealed. During each provide credits to electric Choice Customers. InJanuary 2004,

-~ - quarter of 2003, Detroit Edison recorded a regulatory asset representing the MPSC issued an order implementing a 1cent per kilowatthour, low-income energy assistance credit for residential electric-U, '~ I 'II

customers and terminated the rate equalization credit for GAS INDUSTRY RESTRUCTURING I1--

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1L- AA A..+

uncapped electric Uusiomer Unoice customers. InDecember 2001, the MPSC approved MichCon's application for a Excess Securitization Savings- InJanuary 2004, the MPSC issued voluntary, expanded permanent gas Customer Choice program, an order directing Detroit Edison to file a report by March 15, which replaced the experimental program that expired in March 2004, of the accounting of the savings due to securitization 2002. Effective April 2002, up to 40% of MichCon's customers could and the application of those savings through December 2003. In elect to purchase gas from suppliers other than MichCon. Effective addition, Detroit Edison was requested to include inthe report an April 2003, up to 60% of customers were eligible and by April estimate of the foregone carrying cost associated with the excess 2004, all of MichCon's 1.2 million customers may participate in the securitization savings. program. The MPSC also approved the use of deferred accounting for the recovery of implementation costs of the gas Customer Choice program. As of December 2003, approximately 129,000 BLACKOUT COSTS customers are participating inthe gas Customer Choice program.

On August 14, 2003, failures in the regional power transmission grid caused nine of Detroit Edison's power plants to trip offline, GAS COST RECOVERY PROCEEDINGS which left virtually all of its 2.1 million customers without power.

We estimate that amounts expensed in 2003 related to the black- 2002 Plan Year- In December 2001, the MPSC issued an order that out, excluding lost margins, were approximately $25 million ($16 permitted MichCon to implement GCR factors up to $3.62 per Mcf million net of tax). InOctober 2003, Detroit Edison filed an for January 2002 billings and up to $4.38 per Mcf for the remainder accounting application with the MPSC requesting authority to of 2002. The order also allowed MichCon to recognize a regulatory defer outage related costs associated with the blackout until a asset of approximately $14 million representing the difference future rate proceeding to recover outage costs from customers in a between the $4.38 factor and the $3.62 factor for volumes that manner consistent with the provisions of PA 141. We anticipate an were unbilled at December 31, 2001. The regulatory asset issubject accounting order in the third quarter of 2004. to the 2002 GCR reconciliation process. InMarch 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 GAS RATE PLAN $26.5 million for purposes of calculating the 2002 GCR factor due InSeptember 2003, MichCon filed an application with the MPSC to MichCon's decision to utilize storage gas during 2001 that resulted in a gas inventory decrement for the 2001 calendar year.

for an increase in service and distribution charges (base rates) for its gas sales and transportation customers. The filing requests an Although we recorded a $26.5 million reserve in the first quarter of overall increase inbase rates of $194 million per year (approximately 2003 to reflect the impact of this order, a final determination of 7%increase, inclusive of gas costs), beginning January 1,2005. actual 2002 revenue and expenses including any disallowances or MichCon has requested that the MPSC increase base rates by adjustment will be decided in MichCon's 2002 GCR reconciliation

$154 million per year on an interim basis by April 1,2004. The case which was filed with the MPSC in February 2003. Intervening interim request isbased on a projected revenue deficiency for the parties in this proceeding are seeking to have the MPSC disallow test year 2004. Based on the procedural calendar established in an additional $26 million, representing unbilled revenues at this case, MichCon expects an interim order in the third quarter of December 2001. One party has proposed that half of the $8million 2004 and a final order relating to the $194 million base rate related to the settlement of the Enron bankruptcy also be increase inthe first quarter of 2005. disallowed. The other two parties to the case have recommended that the Enron bankruptcy settlement be addressed inthe 2003 Primary factors that necessitate MichCon's request for increased GCR reconciliation case. A final order in this proceeding is base rates include significant increases in routine and mandated expected in 2004. Inaddition, we filed an appeal of the March infrastructure improvements, increased operation and maintenance 2003 MPSC order with the Michigan Court of Appeals.

expenses, including employee pension and health care costs, and a decline in customer consumption. The filing also requests a 2003 Plan Year- InJuly 2003, the MPSC approved an increase in permanent capital structure based on 50% debt and 50% equity, MichCon's 2003 GCR rate to amaximum of $5.75 per Mcf for the and a proposed ROE of 11.5%. MichCon is also proposing a billing months of August 2003 through December 2003. As of symmetrical ROE sharing mechanism which would provide that December 31, 2003, MichCon has accrued a $19 million regulatory shareholders retain all earnings within a 1%band above and asset representing the under-recovery of actual gas costs incurred.

below the authorized ROE. If the actual ROE falls outside of the band, customers would share between 20% and 80% of the 2004 Plan Year- InSeptember 2003, MichCon filed its 2004 GCR excess or shortfall of earnings, depending on actual ROE. plan case proposing a maximum GCR factor of $5.36 per Mcf.

MichCon agreed to switch from a calendar year to an operational InSeptember 2003, MichCon also filed an application with the year as a condition of its settlement in the 2003 GCR Plan Case.

MPSC for the approval of depreciation rates, which will result in a The operational GCR year would run from April to March of the modest increase in its composite depreciation rate. The Company following year. To accomplish the switch, the 2004 GCR Plan Case anticipates that any depreciation change will be implemented reflects a 15-month transitional period, January 2004 through contemporaneously with a MPSC order in MichCon's base rate case. March 2005. Under the transition proposal, MichCon would file two reconciliations pertaining to the transition period; one addressing the January 2004 to March 2004 period, the other M M .

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addressing the remaining April 2004 to March 2005 period. PROPERTY INSURANCE The plan also proposes a quarterly GCR ceiling price adjustment Detroit Edison maintains several different types of property insurance mechanism. This mechanism allows MichCon to increase the maximum GCR factor to compensate for increases inmarket prices policies specifically for the Fermi 2 plant. These policies cover thereby minimizing the possibility of a GCR under recovery. such items as replacement power and property damage. The Nuclear Electric Insurance Limited (NEIL) is the primary supplier of these insurance polices.

MINIMUM PENSION LIABILITY Detroit Edison maintains a policy for extra expenses, including In December 2002, we recorded an additional minimum pension lia-replacement power costs necessitated by Fermi 2's unavailability bility as required under SFAS No. 87, "Employers'Accounting for due to an insured event. These policies have a 12-week waiting Pensions," with offsetting amounts to an intangible asset and other period and provide an aggregate $490 million of coverage over a comprehensive income. During the first quarter of 2003, the MPSC three-year period.

Staff provided an opinion that the MPSC's traditional rate setting process allowed for the recovery of pension costs as measured by Detroit Edison has $500 million in primary coverage and $2.25 billion SFAS No. 87. Based on the MPSC Staff opinion, management of excess coverage for stabilization, decontamination, debris removal, believes that it will be allowed to recover in rates the minimum repair and/or replacement of property and decommissioning. The pension liability'associated with its regulated operations. In 2003, combined coverage limit for total property damage is $2.75 billion.

we reclassified approximately $585 million ($380 million net of tax) of other comprehensive loss associated with the minimum pension For multiple terrorism losses caused by acts of terrorism not covered liability to a regulatory asset. under the Terrorism Risk Insurance Act (TRIA) of 2002 occurring within one year after the first loss from terrorism, the NEIL policies OTHER would make available to all insured entities up to $3.2 billion plus any amounts recovered from reinsurance, government indemnity, In accordance with a November 1997 MPSC order, Detroit Edison or other sources to cover losses.

reduced rates by $53 million annually to reflect the scheduled reduction in the revenue requirement for Fermi 2. The $53 million Under the NEIL policies, Detroit Edison could be liable for maximum reduction was effective in January 1999. In addition, the November assessments of up to approximately $28 million per event if the loss 1997 MPSC order authorized the deferral of $30 million of storm associated with any one event at any nuclear plant in the United damage costs and amortization and recovery of the costs over a States should exceed the accumulated funds available to NEIL.

24-month period commencing January 1998. After various legal appeals, the Michigan Court of Appeals remanded back to the PUBLIC LIABILITY INSURANCE MPSC for hearing the November 1997 order. In December 2000, the MPSC issued an order reopening the case for hearing. As required by federal law, Detroit Edison maintains $300 million The parties in the case have agreed to a stipulation of fact and of public liability insurance for a nuclear incident. For liabilities waiver of hearing. InJune 2002, the MPSC issued an order arising from a terrorist act outside the scope of TRIA the policy is modifying its 1997 order that will require Detroit Edison to refund subject to one industry aggregate limit of $300 million. Further, approximately $1.5 million after January 1,2004. In July 2002, under the Price-Anderson Amendments Act of 1988 (Act), deferred the Michigan Attorney General filed an appeal with the Michigan premium charges up to $101 million could be levied against each Court of Appeals regarding the June 2002 MPSC Order. licensed nuclear facility, but not more than $10 million per year per facility. Thus, deferred premium charges could be levied against all We are unable to predict the outcome of the regulatory matters dis- owners of licensed nuclear facilities inthe event of a nuclear incident cussed herein. Resolution of these matters is dependent upon at any of these facilities. The Act expired on August 1, 2002.

future MPSC orders, which may materially impact the financial During 2003, the U.S. Congress extended the Act for commercial position, results of operations and cash flows of the company. nuclear facilities through December 31, 2003. However, provisions

ofthe Act remain in effect for existing commercial reactors.

Legislation to extend the Act in conjunction with comprehensive NOTE 5- Nuclear Operations energy legislation is currently under debate in'Congress.

We cannot predict whether the legislation will pass the Congress.

GENERAL Fermi 2, our nuclear generating plant, began commercial operation in DECOMMISSIONING 1988. Fermi 2 has a design electrical rating (net) of 1,150 megawatts.

This plant represents approximately 10% of Detroit Edison's summer The NRC has jurisdiction over the decommissioning of nuclear power net rated capability. The net book balance of the Fermi 2 plant was plants and requires decommissioning funding based upon a formula.

written off at December 31, 1998, and an equivalent regulatory The MPSC and FERC regulate the recovery of costs of decommission-asset was established. In 2001, the Fermi 2 regulatory asset was ing nuclear power plants and both require the use of external trust securitized. See Note 47 Regulatory Matters. Detroit Edison also funds to finance the decommissioning of Fermi 2. Rates approved by owns Fermi 1,a 'nuclear plant that was shut down in 1972 and is the MPSC provide for the recovery of decommissioning costs of Fermi currently being' dcommissioned. The Nuclear Regulatory Commission 2. Detroit Edison iscontinuing to fund FERC jurisdictional amounts (NRC) has jurisdiction over the licensing and operation of Fermi 2 for decommissioning even though explicit provisions are not included and the decommissioning of Fermi 1.

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in FERC rates. We believe the MPSC and FERC collections will be Ludington adequate to fund the estimated cost of decommissioning using the Hydroelectric Belle Pumped NRC formula. River Storage In-service date 1984-1985 1973 Detroit Edison has established a restricted external trust to hold Ownership interest

49 %

funds collected from customers for decommissioning and the Investment fin Millions) $ 1,587 $ 197 disposal of low-level radioactive waste. Detroit Edison collected Accumulated depreciation (inMillions) $ 711 $ 114

$36 million in 2003, $42 million in 2002 and $38 million in 2001 from customers for decommissioning and low-level radioactive *Detrokt Edison's ownership interest is63% inUnit No. 1,81% of the facilities waste disposal. Net unrealized investment gains of $62 million and applicable to Belle River used jointly by the Belle River and St Clair Power Plants and 75% incommon facilities used at Unit No. 2.

losses of $39 million in 2003 and 2002, respectively, were recorded as adjustments to the nuclear decommissioning trust funds and regulatory assets. At December 31, 2003, investments in the BELLE RIVER external trust consisted of approximately 54.8% in publicly traded The Michigan Public Power Agency (MPPA) has an ownership equity securities, 44.4% in fixed debt instruments and 0.8% in interest in Belle River Unit No. 1 and other related facilities. The cash equivalents. MPPA is entitled to 19% of the total capacity and energy of the plant (1,026 MW) and is responsible for the same percentage of At December 31, 2003 and 2002, Detroit Edison had external the plant's operation, maintenance and capital improvements costs.

decommissioning trust funds of $474 million and $377 million, respectively, for the future decommissioning of Fermi 2. At December 31, 2003 and 2002, Detroit Edison had an additional $22 LUDINGTON HYDROELECTRIC PUMPED STORAGE million for the decommissioning of Fermi 1. Detroit Edison also Operation, maintenance and other expenses of the Ludington had an external decommissioning trust fund of $22 million for Hydroelectric Pumped Storage Plant (1,872 MW) are shared by low-level radioactive waste disposal costs at December 31, 2003 Detroit Edison and Consumers Energy Company in proportion to and $17 million as of December 31, 2002. It isestimated that the their respective plant ownership interests.

cost of decommissioning Fermi 2,when its license expires in 2025, will be $1.0 billion in 2003 dollars and $3.4 billion in 2025 dollars, using a 6%inflation rate. In2001, the company began the NOTE 7 - Income Taxes decommissioning of Fermi 1,with the goal of removing the We file a consolidated federal income tax return.

radioactive material and terminating the Fermi 1 license. The decommissioning of Fermi 1 isexpected to be complete by 2009. Total income tax benefit varied from the statutory federal income tax rate for the following reasons:

As aresult of adopting SFAS No. 143, Detroit Edison recorded a retirement obligation liability for the decommissioning of Fermi 1 (Dollars inMillions) 2003 2002 2001 and 2 and reversed previously recognized decommissioning liabilities. Effective federal income tax rate (34.4)% (16.7)% (62.6)%

We continue to have liability for the removal of the non-nuclear Income tax expense at 35%

portion of the plants of $67 million at December 31, 2003. statutory rate $ 125 $ 175 $ 68 Section 29 tax credits (241) (250) (165)

NUCLEAR FUEL DISPOSAL COSTS Investment tax credits (8) (9) (8)

Depreciation (4) 2 (12)

Inaccordance with the Federal Nuclear Waste Policy Act of 1982, - Goodwill amortization - - 10 Detroit Edison has a contract with the U.S. Department of Energy Research expenditures tax credits - - (7)

(DOE) for the future storage and disposal of spent nuclear fuel Employee Stock Ownership from Fermi 2. Detroit Edison is obligated to pay the DOE a fee of, Plan dividends (5) (4) (4) one mill per net kilowatthour of Fermi 2 electricity generated and Other-net 10 2 (1) sold. The fee isa component of nuclear fuel expense. Delays have Income taxes benefit associated occurred inthe DOE's program for the acceptance and disposal of with continuing operations S (123) $ (84) $ (119) spent nuclear fuel at a permanent repository. Until the DOE isable to fulfill its obligation under the contract, Detroit Edison is responsible Components of income tax benefit were as follows:

for the spent nuclear fuel storage. Detroit Edison estimates that (inMillions) 2003 2002 2001 existing storage capacity will be sufficient until 2007. Detroit Continuing Operations Edison has entered into litigation against the DOE for damages caused Current federal and other by the DOE not accepting spent nuclear fuel on a timely basis. income tax expense $ 14 $ 135 $ 1 Deferred federal income tax benefit (137) (219) (1120)

NOTE 6 - Jointly Owned Utility Plant (123) (84) (119)

Detroit Edison's share of jointly owned utility plants at December Discontinued operations 61 25 9 31, 2003 was as follows: Total S (62) $ (59) $ (110)

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Internal Revenue Code Section 29 provides a tax credit for qualified to purchase all of the outstanding common stock of MCN Energy.

fuels produced and sold by a taxpayer to an unrelated party during See Note 3- Acquisitions and Dispositions. The newly issued the taxable year. Section 29 tax credits earned but not utilized of shares were valued at the average market price of our common

$497 million are carried forward indefinitely as alternative minimum stock on February 28, 2001, the announcement date of the revised tax credits. The majority of our tax credit properties, including all merger agreement.

of our synfuel projects, have received private letter rulings from the Internal Revenue Service (IRS) that provide assurance as to the In2001, DTE Energy repurchased approximately 10.5 million shares appropriateness of using these credits to offset taxable income, of common stock with a total cost of approximately $438 million.

however, these tax credits are subject to IRS audit and adjustment.

Under the DTE Energy Company Long-Term Incentive Plan, we grant As a result of the MCN Energy acquisition we have a net operating non-vested stock awards to management At the time of grant, DTE loss carry forward of $239 million that expires inyears 2018 Energy records the fair value of the non-vested awards as unearned through 2020. We do not believe that a valuation allowance is compensation, which isreflected as a reduction in common stock.

required, as we expect to utilize the loss carry forward prior to its The number of non-vested stock awards isincluded in the number expiration. of common shares outstanding; however, for purposes of computing basic earnings per share, non-vested stock awards are excluded.

Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences between the tax basis of SHAREHOLDERS' RIGHTS PLAN assets or liabilities and the reported amounts in the financial statements. Deferred tax assets and liabilities are classified as We have a Shareholders' Rights Plan designed to maximize current or noncurrent according to the classification of the related shareholders' value should DTE Energy be acquired. The rights assets or liabilities. Deferred tax assets and liabilities not related are attached to and trade with shares of DTE Energy's common to assets or liabilities are classified according to the expected stock until they are exercisable upon certain triggering events.

reversal date of the temporary differences. The rights expire in 2007.

Deferred income tax assets (liabilities) were comprised of the EARNINGS PER SHARE following at December 31:

We report both basic and diluted earnings per share. Basic earnings (inMillions) 2003 2002 per share iscomputed by dividing income from continuing operations Property $ (1,124) $ (1,179) by the weighted average number of common shares outstanding Securitized regulatory assets (827) (871) during the period. Diluted earnings per share assume the issuance Alternative minimum tax credit carry forward 497 381 of potentially dilutive common shares outstanding during the period Merger basis differences 132 186 and the repurchase of common shares that would have occurred Pension and benefits (50) 216 with proceeds from the assumed issuance. Diluted earnings per share assume the exercise of stock options, vesting of non-vested Net operating loss 84 114 stock awards, and the issuance of performance share awards. A Other 380 282 reconciliation of both calculations ispresented inthe following table:

$ (908) $ (871)

Deferred income tax liabilities S (2,525) $ (2,564) (inMillions, exceptper share amounts) 2003 2002 2001 Deferred income tax assets 1,617 1,693 Basic Earnings per Share S (908) $ (871) Income from continuing operations S 480.4 $ 585.7 S 308.7 Average number of common The IRS iscurrently conducting audits of our federal income tax shares outstanding 167.7 164.0 153.1 returns for the years 1998 through 2001 and of the MCN Energy Earnings per share of common federal income tax returns for 1999 through May 31, 2001. In stock based on average number of addition, four of our synfuel facilities are under audit by the IRS shares outstanding S 2.87 $ 3.57 $ Z02 for 2001. We believe that our accrued tax liabilities are adequate Diluted Earnings per Share for all years. Income from continuing operations S 480.4 $ 585.7 $ 308.7 Average number of common shares outstanding 167.7 164.0 153.1 NOTE 8 - Common Stock and Earnings Incremental shares from stock-based awards .6 .8 .7 Per Share Average number of dilutive shares outstanding 168.3 164.8 153.8 COMMON STOCK Earnings per share of common InJune 2002, we issued 6.325 million shares of common stock at stock assuming issuance of

$43.25 per share, grossing $274 million. Net proceeds from the incremental shares S 2.85 $ 3.55 $ 2.01 offering were approximately $265 million.

Options to purchase approximately five million shares of common On May 31, 2001, we issued approximately 29 million shares of stock were not included in the computation of diluted earnings per common stock, valued at $1.06 billion, as part of the consideration share because the options' exercise price was greater than the III' 'I

average market price of the common shares, thus making these

Issued $172.5 million of DTE Energy equity-linked debt securities securities anti-dilutive. as subsequently discussed Issued $225 million of Detroit Edison senior notes bearing NOTE 9 - Long-Term Debt and interest at 5.20 %and maturing in2012 Preferred Securities

Issued $225 million of Detroit Edison senior notes bearing LONG TERM DEBT -interest at 6.35 %and maturing in2032

Issued $64 million of Detroit Edison tax exempt bonds bearing Our long-term debt outstanding and weighted average interest interest at 5.45% and issued $56 million of Detroit Edison tax rates of debt outstanding at December 31 were: exempt bonds bearing interest at 5.25%, both maturing in 2032, (inMillions) 2003 2002 Inthe years 2004 - 2008, our long-term debt maturities are DTE Energy Debt Unsecured $467 million, $512 million, $680 million, $174 million and 6.6% due 2004 to 2033 $ 2005 $ 1,948 $455 million, respectively.

Detroit Edison Taxable Debt Principally Secured Remarketable Securities 6.2% due 2005 to 2034 1,485 1,812 At December 31, 2003, $175 million of notes of Detroit Edison and Detroit Edison Tax Exempt Revenue Bonds MichCon were subject to periodic remarketings, no remarketings 5.7% due 2004 to 2032 1,175 1,208 will take place in 2004. We direct the remarketing agents to MichCon Taxable Debt, Principally Secured remarket these securities at the lowest interest rate necessary to 6.5% due 2005 to 2039 772 775 produce a par bid. Inthe event that a remarketing fails, we would Quarterly Income Debt Securities (QUIDS) be required to purchase these securities.

7.8% due 2026 to 2038 385 385 Non-Recourse Debt 78 119 Quarterly Income Debt Securities (QUIDS)

Other Long-Term Debt 106 329 6,006 6,576 Each series of QUIDS provides that interest will be paid quarterly.

However, Detroit Edison has the right to extend the interest Less amount due within one year (382) (920) payment period on the QUIDS for up to 20 consecutive interest S 5,624 $ 5,656 payment periods. Interest would continue to accrue during the Securitization Bonds $ 1,585 $ 1,673 deferral period. If this right is exercised, Detroit Edison may not Less amount due within one year (89) (88) declare or pay dividends on, or redeem, purchase or acquire, any of

$ 1,A96 $ 1,585 its capital stock during the deferral period.

Equity-Linked Securities S 185 $ 191 Trust Preferred - Linked Securities Equity-Linked Securities 8.625%due2038 $ 103 $ 103 7.8% due 2032 186 186 InJune 2002, we issued 6.9 million equity security units with S 289$ 289 gross proceeds from the issuance of $172.5 million. An equity qpciiritv unit cnnsists nf a stnok nurhise rcnntrart and a senior note of DTE Energy. Under the stock purchase contracts, we will During 2003 and 2002, we issued and optionally redeemed sell, and equity security unit holders must buy, shares of DTE long-term debt consisting of the following: Energy common stock inAugust 2005 for $172.5 million. The issue 2003 price per share and the exact number of common shares to be sold

Issued $400 million of DTE Energy 6-3/8% senior notes maturing is dependent on the market value of ashare in August 2005. The in April 2033. Inconjunction with this issuance, DTE Energy issue price will be not less than $43.25 or more than $51.90 per exchanged $100 million principal amount of existing Enterprises common share, with the corresponding number of shares issued of debt due April 2008. The exchange premium and other costs not more than 4.0 million or less than 3.3 million shares. We are associated with the original debt were deferred and amortized also obligated to pay the security unit holders a quarterly contract to interest expense over the term of the new debt. adjustment payment at an annual rate of 4.15% of the stated

Redeemed $100 million of DTE Energy 6.17% Remarketed amount until the purchase contract settlement date. We recorded Notes maturing in 2038 the present value of the contract adjustment payments of $26 million

Issued $49 million of Detroit Edison 5.5% tax exempt bonds- in long-term debt with an offsetting reduction in shareholders' maturing in2030 - equity. The liability is reduced as the contract adjustment

Redeemed $49 million of Detroit Edison 6.55% tax-exempt paymens ade.

bonds maturing in 2024 .Each senior note has astated value of $25, pays an annual interest

Issued $200 million of MichCon 5.7% senior notes maturing in rate of 4.60% and matures in August 2007. The senior notes are March 2033 : pledged as collateral to secure the security unit holders' obligation 2002 : to purchase DTE Energy common stock under the stock purchase contracts. The security unit holders may satisfy their obligations

Issued $200 million of DTE Energy senior notes bearing interest under the stock purchase contracts by allowing the senior notes at 6.65 %and maturing in2009 - to be remarketed with proceeds being paid to DTE Energy as III 'i . I II

consideration for the purchase of stock under the stock purchase - At December 31, 2003, Detroit Edison had 6.75 million shares of contracts. Alternatively, holders may choose to continue holding preferred stock with a par value of $100 per share and 30 million the senior notes and use cash as consideration for the purchase of shares of preference stock with a par value of $1 per share stock under the stock purchase contracts. authorized, with no shares issued.

Net proceeds from the equity security unit issuance totaled $167 At December 31, 2003, Enterprises had 25 million shares of preferred million. Expenses incurred in connection with this issuance totaled stock without par value authorized, with no shares issued.

$5.6 million and were allocated between the senior notes and the stock purchase'contracts. The amount allocated to the senior At December 31, 2003, MichCon had 7 million shares of preferred notes was deferred and will be recognized as interest expense stock with a par value of $1 per share and 4 million shares of over the term of the notes. The amount allocated to the purchase preference stock with a par value of $1per share authorized, with contracts was charged to equity. no shares issued.

Trust Preferred-Linked Securities NOTE 10 - Short-Term Credit Arrangements We have interests in various unconsolidated trusts that were and Borrowings formed for the sole purpose of issuing preferred securities and lending the gross proceeds to DTE Energy. The sole assets of the In October 2003, we entered into a $350 million 364-day unsecured trusts are debt securities of DTE Energy with terms similar to those revolving credit facility and a $350 million three-year unsecured of the related preferred securities. Payments we make are used by revolving credit facility with a syndicate of banks. These credit the trusts to make cash distributions on the preferred securities it facilities may be utilized for general corporate borrowings, but has issued. primarily are intended to provide liquidity support for DTE Energy's commercial paper program up to $700 million. In addition, we had We have the right to extend interest payment periods on the debt approximately $100 million'of letters of credit outstanding against securities. Should we exercise this right, we cannot declare or pay these facilities at December 31, 2003, which represent guarantees to dividends on, or redeem, purchase or acquire, any of our capital third parties under which no amounts were outstanding. These stock during the deferral period. agreements require the Cormpany to maintain a debt to total capitalization ratio of no more than .65 to 1 and "earnings before DTE Energy has issued certain guarantees with respect to payments interest, taxes, depreciation and amortization" (EBITDA) to interest on the preferred securities. These guarantees, when taken together ratio of no less than 2 to 1.DTE Energy is currently incompliance with our obligations under the debt securities and related indenture, with these financial covenants. Also, in October 2003, DTE Energy's provide full and unconditional guarantees of the trusts' obligations wholly-owned subsidiaries, Detroit Edison and MichCon, entered.

under the preferred securities. into similar revolving credit facilities. Detroit Edison entered into a.

$137.5 million, 364-day facility and a $137.5 million, three-year Financing costs for these issuances were paid for and deferred by facility. MichCon entered into a $162.5 million, 364-day facility and DTE Energy. These costs are being amortized using the straight-line a $162.5 million, three-year facility. Should either Detroit Edison or method over the estimated lives of the related securities. MichCon have delinquent debt obligations of at least $25 million to any creditor, such delinquency will be considered a default The $100 million of 8.625% preferred securities, due 2038, was under DTE Energy's credit agreements.

called in December 2003 and was redeemed in January 2004.

Accordingly, the underlying DTE Energy debt security was also As of December 31, 2003, we had outstanding commercial paper simultaneously redeemed. of $239 million and other short-term borrowings of $31 million.

At December 31, 2002, we had outstanding commercial paper of Cross Default Provisions $413 million and other short-term borrowings of $1million. 4 Substantially all of the net utility properties of Detroit Edison and MichCon are subject to the lien of mortgages. Should Detroit Detroit Edison has a $200 million short-term financing agreement Edison or MichCon fail to timely pay their indebtedness under secured by customer accounts receivable. This agreement contains . 1 certain covenants related to the delinquency of accounts receivable.

these mortgages, such failure will create cross defaults in the i indebtedness of DTE Energy Corporate. Detroit Edison is currently in compliance with these covenants. We had $100 million outstanding under this financing agreement at December 31, 2003. iP PREFERRED AND PREFERENCE SECURITIES -

i AUTHORIZED AND UNISSUED The weighted average interest rates for short-term borrowings s .

At December 31, 2003, DTE Energy had 5million shares of were 1.9% and 1.7% at December 31, 2003 and 2002, respectively.

. r preferred stock without par value authorized, with no shares issued. Of such amount, 1.6 million shares are reserved for NOTE 11 - Capital and Operating Leases issuance in accordance with the Shareholders' Rights Plan. . P Lessee - We lease various assets under capital and operating I leases, including locomotives, coal cars, a gas storage field, office I buildings, a warehouse, computers, vehicles and other equipment. I

. I tI r

I I ' II I I

The lease arrangements expire at various dates throu gh 2029.

The accounting for changes in fair value depends upon the purpose Portions of the office buildings are subleased to tenar its. of the derivative instrument and whether it isdesignated as a hedge and qualifies for hedge accounting.

Future minimum lease payments under non-cancelabli eleases at

Special accounting is allowed for a derivative instrument December 31, 2003 were: qualifying as a hedge and designated as a hedge for the variability of cash flow associated with a forecasted transaction.

Capital OLperatin Gain or loss associated with the effective portion of the hedge (inMillions)

Leases 2004 S 12 - 72 is recorded in other comprehensive income. The ineffective 2005 12 70 portion isrecorded to earnings. Amounts recorded in other comprehensive income will be reclassified to net income when 2006 14 -58 the forecasted transaction affects earnings.

2007 10

if a cash flow hedge isdiscontinued because it islikely the 2008 11 forecasted transaction will not occur, net gains or losses are Thereafter 50 457 immediately recorded into earnings.

Total minimum lease payments 109

$ '7

Special accounting is allowed for a derivative instrument Less imputed interest (28) qualifying as a hedge and designated as a hedge of the Present value of net minimum changes infair value of an existing asset, liability or firm lease payments 81 Less current portion (6) commitment. Gain or loss on the hedging instrument isrecorded Non-current portion $ 75 into earnings. The gain or loss on the underlying asset, liability or firm commitment is also recorded into earnings.

Total minimum lease payments for operating leases have not been Our primary market risk exposure isassociated with commodity reduced by future minimum sublease rentals totaling $8million prices, credit, interest rates and foreign currency. We have risk under non-cancelable subleases expiring at various dates to 2019. management policies to monitor and decrease market risks. We use derivative instruments to manage some of the exposure.

Rental expenses for operating leases was $73 million in 2003, $40 Except for the activities of the Energy Marketing & Trading million in 2002 and $19 million in 2001. segment, we do not hold or issue derivative instruments for trading purposes. The fair value of all derivatives isshown as Lessor- MichCon leases a portion of its pipeline system to the Vector Pipeline Partnership through a capital lease contract that "assets or liabilities from risk management and trading activities" expires in 2020, with renewal options extending for five years. in the consolidated statement of financial position.

The components of the net investment inthe capital lease' at December 31, 2003, were as follows: COMMODITY PRICE RISK (inMillions) Regulated Operations 2004 - $ 9 Detroit Edison uses forward energy, capacity, and futures contracts 2005 9 to manage changes in the price of electricity and natural gas.

2006 9 Changes in fair value of derivatives are recognized currently in 2007 9 earnings, unless hedge accounting and the normal purchase 2008 9 and sale exceptions apply. Changes in fair value of derivatives Thereafter 107 designated and qualifying as an effective cash flow hedge are Total minimum future lease receipts 152 recorded as a component of other comprehensive loss and reclas-Residual value of leased pipeline 40 sified into earnings. Any changes infair value of ineffective cash Less - unearned income (109) flow hedges are recognized currently in earnings. Changes in fair Net investment incapital lease 83 value of normal contracts are not recorded. These contracts are Less-current portion - (1) recorded on an accrual basis. There were no commodity price risk

$ 82 cash flow hedges for regulated operations at December 31, 2003.

Detroit Edison's operating policy isthat transactions for electricity NOTE Financial and Other or fuel are not done in a speculative manner, but to optimize the Derivative Instruments - efficiency of the power supply costs. All contracts entered into by Detroit Edison to sell energy are physically delivered. All purchases We comply with SFAS No. 133, Accounting for Derivative Instruments of power are considered capacity contracts under SFAS No. 133 (as and Hedging Activities. SFAS No. 133 established accounting and amended by SFAS No. 138 and SFAS No. 149). Inaddition, the summer reporting standards for derivative instruments and hedging activities. shortfall calculation submitted to the MPSC is insupport of our short Listed below are important SFAS No. 133 requirements: positions. It isbased on management's judgment of the above criteria that Detroit Edison's commodity contracts are considered normal.

All derivative instruments must be recognized as assets or liabilities and measured at fair value, unless they meet the MichCon has firm-priced contracts for a substantial portion of its normal purchases and sales exemption. expected gas supply requirements through 2004. These contracts I, ' ' 'I

are designated and qualify for the normal purchases exception FOREIGN CURRENCY RISK under SFAS No.133. Accordingly, MichCon does not account for such contracts as derivatives. During 2003, we entered into forward purchases of foreign currency contracts to hedge fixed Canadian dollar commitments existing under power purchase and sale contracts and gas transportation Non-Regulated Operations contracts. We entered into these contracts to mitigate any price Energy Marketing & Trading markets and trades wholesale electricity volatility with respect to fluctuations of the Canadian dollar relative and natural gas physical products, trades financial instruments, to the U.S. dollar. Certain of these contracts are designated as and provides risk management services utilizing energy commodity cash flow hedges and were fully effective as of December 31, 2003.

derivative instruments. Forwards, futures, options and swap agreements are used to manage exposure to the risk of market price FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS and volume fluctuations on its operations. This risk minimization strategy isbeing accounted for by marking to market its commodity The fair value of financial instruments isdetermined by using forwards and financial derivatives so they substantially offset. various market data and other valuation techniques. The table This fair value accounting better aligns financial reporting with the below shows the fair value relative to the carrying value for I way the business ismanaged and its performance measured. non-affiliated long-term debt securities: i Unrealized gains and losses resulting from marking to market i commodity-related physical and financial derivatives utilized in 2003 2002 i

trading operations are recorded as adjustments to revenues. Fair Carrying Fair Carrying i Value Value - Value Value i

Energy Marketing & Trading experiences earnings volatility as a Long-Term Debt $8.5 billion $7.9 billion $8.9 billion $8.2 billion I i

result of its gas inventory and other non-derivative assets that do i i

i not qualify for mark to market accounting under generally accepted NOTE 13 - Commitments and Contingencies f accounting principles. Although the risks associated with these asset positions are substantially offset, requirements to revalue SYNTHETIC FUEL OPERATIONS i the underlying trades will result in unrealized gains and losses that i i I will eventually reverse upon settlement We operate nine synthetic fuel production facilities, four of which I are wholly owned. Synfuel facilities chemically change coal, including waste and marginal coal, into asynthetic fuel as CREDIT RISK determined under applicable IRS rules. Section 29 of the Internal We are exposed to credit risk if customers or counterparties do not Revenue Code provides tax credits for the production and sale of comply with their contractual obligations. We maintain credit policies solid synthetic fuels produced from coal. To qualify for the Section that significantly minimize overall credit risk. These policies include 29 tax credits, the synthetic fuel must meet three primary conditions:

an evaluation of potential customers' and counterparties' financial 11)there must be a significant chemical change in the coal feedstock, condition, credit rating, collateral requirements or other credit (2)the product must be sold to an unaffiliated entity, and (3)the enhancements such as letters of credit or guarantees. We use production facility must have been placed in service before July 1, standardized agreements that allow the netting of positive and 1998. Inaddition to meeting the qualifying conditions, ataxpayer negative transactions associated with a single counterparty. must have sufficient taxable income to earn the Section 29 credits.

INTEREST RATE RISK InMay 2003, the IRS suspended the issuance of PLRs relating to synthetic fuel projects pending their review of issues concerning We use interest rate swaps to hedge the risk associated with chemical change which isthe basis for earning Section 29 tax interest rate payments and expense. During 2000, we entered credits. InOctober 2003, the IRS concluded its assessment of into a series of interest rate swaps and treasury locks to limit our the chemical change process involved in synfuel production and sensitivity to market interest rate risk associated with the issuance resumed issuing PLRs. The IRS determined that the test procedures of long-term debt used to acquire MCN Energy. Such instruments and results used by taxpayers are scientifically valid if the were designated as cash flow hedges. Inthe first quarter of procedures are applied in a consistent and unbiased manner.

2001, a loss of approximately $5million was reclassified from The Company believes that its synthetic fuel facilities currently accumulated other comprehensive loss into earnings. We made meet the new, more stringent sampling and data/record retention this decision since it was probable that certain transactions requirements announced by the IRS. We had previously received associated with the issuance of long-term debt would not occur favorable PLRs from the IRS on seven of our nine synfuel plants.

within the originally anticipated time frame. This loss was reported InNovember 2003, we received favorable PLRs for the remaining as a component of interest expense in the consolidated statement two synfuel plants. The IRS iscurrently reviewing procedures and of operations. In2001, we issued long-term debt with varying results at four of our synfuels plants in conjunction with their-maturities and terminated these hedges at a cost of $83 million. audits of our federal income tax returns for 2001. We believe our The corresponding loss on these instruments is included in other synthetic fuel plants operate in accordance with the PLRs.

comprehensive loss. During the next 30 years, amounts recorded Through December 31, 2003, we have generated approximately inother comprehensive loss will be reclassified to interest expense $484 million of synfuel tax credits.

as the related interest affects earnings. In2004 we estimate reclassifying $10 million of losses into interest expense.

To optimize tax credits generated from these facilities, we, more accurately recognize the value of a utility's personal property.

implemented a series of initiatives, including selling interests in The new tables became effective in 2000 and are currently used to synfuel projects and monetizing certain in-the-money derivatives calculate property tax expense. However, several local taxing contracts which allowed us to fully utilize the tax credits generated jurisdictions have taken legal action attempting to prevent the STC in 2003. We are continuing our efforts to sell interests in all of our from implementing the new valuation tables and have continued to synfuel projects. Sales of interests in synfuel projects allow us to prepare assessments based on the superseded tables. The legal accelerate cash flow and taxable income, while maintaining a: actions regarding the appropriateness of the new tables were stable net income base. As the sale of interests in synfuel projects before the Michigan Tax Tribunal (MTT) which, in April 2002, usually requires the reconfirmation of the PLR, the timing and number issued its decision essentially affirming the validity of the STC's of our synfuel project interest sales were influenced by the IRS' new tables. InJune 2002, petitioners inthe case filed an appeal five month suspension of issuing new and reconfirming PLRs. of the MTT's decision with the Michigan Court of Appeals. On January 20, 2004, the Michigan Court of Appeals upheld the validity The U.S. Senate Permanent Subcommittee on Investigations of the of the new tables.

Committee on Governmental Affairs has begun an investigation of' the synthetic fuel industry and its producers. DTE Energy, along with Detroit Edison and MichCon record property tax expense based other industry participants, received a request to produce certain on the new tables. Detroit Edison and MichCon will seek to apply documents pertaining to its synfuel operations. DTE Energy isin the new tables retroactively and to ultimately settle the pending the process of complying with this request. We have no further tax appeals related to 1997 through 1999. This isa solution knowledge of the scope of the investigation, when the investigation supported by the STC in the past.

will be completed or the potential results of the investigation.

ENERGY GAS ENVIRONMENTAL MATTERS GUARANTEES Prior to the construction of major natural gas pipelines, gas for Incertain circumstances we enter into contractual guarantees. We heating and other uses was manufactured from processes involving may guarantee another entity's obligation inthe event it fails to coal, coke or oil. Enterprises (MichCon and Citizens) owns, or previously perform. We may provide guarantees in certain indemnification owned, 18 such former manufactured gas plant (MGP) sites.

agreements. Finally, we may provide indirect guarantees of the indebtedness of others. Below are the details of specific material During the mid-1 980's, Enterprises conducted preliminary guarantees we currently provide. Our other guarantees are not environmental investigations at former MGP sites, and some individually material and total approximately $26 million at contamination related to the by-products of gas manufacturing December 31, 2003. was discovered at each site. The existence of these sites and the results of the environmental investigations have been reported to Sale of Tax Credit Properties the MDEQ. None of these former MGP sites is on the National Priorities List prepared by the EPA.

We have provided certain guarantees and indemnities inconjunction with the sales of interests in our synrfuel facilities. The guarantees Enterprises isremediating seven of the former MGP sites and cover general commercial, environmental and tax-related exposure conducting more extensive investigations at six other former and will survive until 90 days after expiration of all applicable MGP sites. Enterprises received MDEQ closure of one site and a statute of limitations, or indefinitely, depending on the nature of determination that it isnot a responsible party for three other sites.

the guarantee. We estimate that our maximum liability under Enterprises received closure from the EPA in 2002 for one site.

these guarantees at December 31, 2003 totals $300 million.

In 1984, Enterprises established a $12 million reserve for Parent Company Guarantee of Subsidiary Obligations environmental investigation and remediation. During 1993, We have issued guarantees for the benefit of various non-regulated MichCon received MPSC approval of a cost deferral and rate subsidiary transactions. Inthe event that DTE Energy's credit recovery mechanism for investigation and remediation costs rating isdowngraded below investment grade, certain of these : incurred at former MGP sites in excess of this reserve.

guarantees would require us to post cash or letters of credit Enterprises employed outside consultants to evaluate remediation valued at approximately $290 million at December 31, 2003.

alternatives for these sites, to assist in estimating its potential This estimated amount fluctuates based upon the provisions and liabilities and to review its archived insurance policies. The maturities of the underlying agreements.

findings of these investigations indicate that the estimated total expenditures for investigation and remediation activities for these PERSONAL PROPERTY TAXES sites could range from $30 million to $170 million based on Detroit Edison, MichCon and other Michigan utilities have asserted undiscounted 1995 costs. As a result of these studies, Enterprises that Michigan's valuation tables result inthe substantial overvaluation accrued an additional liability and a corresponding regulatory asset of utility personal property. Valuation tables established by the of $35 million during 1995.

Michigan State Tax Commission (STC) are used to determine the taxable value of personal property based on the property's age. During 2003, Enterprises spent $1.5 million investigating and InNovember 1999, the STC approved new valuation tables that remediating these former MGP sites. At December 31, 2003, the

I reserve balance was $23 million of which $5million was classified companies expiring on various dates through the year 2021.

as current. Any significant change inassumptions, such as remediation Enterprises is also committed to pay demand charges of techniques, nature and extent of contamination and regulatory approximately $68 million during 2004 related to firm purchase requirements, could impact the estimate of remedial action costs and transportation agreements.

for the sites and, therefore, have an effect on the company's financial position and cash flows. However, we believe the cost deferral InFebruary 2004, Enterprises terminated a long-term gas exchange and rate recovery mechanism approved by the MPSC will prevent agreement and modified our future purchase commitments under a environmental costs from having a material adverse impact on our related transportation agreement with an interstate pipeline company,.

results of operations'. effective March 31, 2004. The agreements were at rates that were not reflective of current market conditions and had been fair valued COMMITMENTS under generally accepted accounting principles. In2002, the fair value of the transportation agreement was frozen when it no Detroit Edison has an Energy Purchase Agreement to purchase - longer met the definition of 'aderivative as a result of FERC Order, steam and electricity from the Greater Detroit Resource Recovery 637. The fair value amounts were being amortized to income over Authority (GDRRA). Under the Agreement, Detroit Edison will the life of the related agreements, representing a net liability of purchase steam through 2008 and electricity through June 2024. approximately $75 million as of December 31, 2003. We are In 1996, aspecial charge to income was recorded that included a currently negotiating new agreements with the interstate pipeline.

reserve for steam purchase commitments in excess of replacement company. We will record an appropriate adjustment to the liability costs from 1997. through 2008. The reserve for steam purchase after all related agreements have been finalized.

commitments is being amortized to fuel, purchased power and gas expense with non-cash accretion expense being recorded through At December 31, 2003, we have also entered into long-term fuel 2008. In2001, due to changes in estimated future replacement supply commitments through 2008 of approximately $405 million.

costs we reduced the reserve for future steam purchase commitments We estimate that 2004 base level capital expenditures will be by $22 million. We purchased $30 million of steam and electricity $1.0 billion. We have made certain commitments in connection in 2003, $37 million in2002 and $41 million in 2001. We estimate with expected capital expenditures. r annual steam and electric purchase commitments from 2004 until 2008 will not exceed $150 million. As discussed in Note 3 - BANKRUPTCIES Acquisitions and Dispositions, in January 2003, we sold the steam heating business of Detroit Edison to Thermal Ventures 11, LLP. We purchase and sell electricity, gas, coal and coke from and to Due to terms of the sale, Detroit Edison remains contractually numerous companies operating in the steel, automotive, energy obligated to GDRRA until 2008 and recorded an additional liability and retail industries. A number of customers have filed for of $20 million for future commitments. Also, we have guaranteed bankruptcy protection under Chapter 11 of the U.S. Bankruptcy bank loan's that Thermal Ventures 11, LLP may use for capital Code. We have negotiated or are currently involved in negotiations improvements to the steam heating system. with each of the companies, or their successor companies, that have filed for bankruptcy protection. We regularly review The EPA issued ozone transport regulations and, in December, contingent matters relating to purchase and sale contracts and 2003, proposed additional emission regulations relating to ozone, record provisions for amounts considered probable of loss. We fine particulate and mercury air pollution. The new rules have led believe our previously accrued amounts are adequate for probable to additional controls on fossil-fueled power plants to reduce nitrogen losses. The final resolution of these matters isnot expected to oxides, sulfur dioxide, carbon dioxide and particulate emissions. have a material effect on our financial statements in the period To comply with these new controls, Detroit Edison has spent they are resolved.

approximately $560 million through December 2003 and estimates that it will spend approximately $40 million in 2004 and incur up to OTHER an additional approximately $1.2 billion of future capital expenditures over the next five to eight years to satisfy both the existing and Several Midwest utilities seek to recover lost transmission revenues proposed new control requirements. Under the June 2000 Michigan associated with the creation of multiple regional transmission restructuring legislation, beginning January 1,2004, annual return organizations in the Midwest. Positions advocated by several parties of and on this capital expenditure, in excess of current depreciation in a FERC proceeding could require that Detroit Edison and its levels, would be deferred in ratemaking, until after the expiration customers be responsible for increased transmission costs. Detroit of the rate cap period, presently expected to end December 31, 2005. Edison continues to actively participate in this proceeding and depending upon the outcome would subsequently seek rate recovery To ensure a reliable supply of natural gas at competitive prices, of these costs.

Enterprises has entered into long-term purchase and transportation contracts with various suppliers and producers. Ingeneral, We are involved in certain legal, regulatory, administrative and purchases are under fixed price and volume contracts or formulas environmental proceedings before various courts, arbitration based on market prices. Enterprises has firm purchase commitments panels and governmental agencies concerning matters arising in through 2010 for approximately 342 Bcf of gas. Enterprises the ordinary course of business. These proceedings include certain expects that sales, based on warmer-than-normal weather, will contract disputes, environmental reviews and investigations, exceed its minimum purchase commitments. Enterprises has audits, inquiries from various regulators, and pending judicial matters.

long-term transportation and storage contracts with various We cannot predict the final disposition of such proceedings. We

,, II .4 'i £ I

regularly review legal matters and record provisions for claims that (inMillions) 2003 2002 are considered probable of loss. The resolution of pending proceedings Measurement Date December31 December31 is not expected to have a material effect on our operations or Accumulated Benefit Obligation financial statements in the period they are resolved. at the End of the Period S 2.556 $ 2,299 Projected Benefit Obligation See Note 4 and Note 5 for a discussion of contingencies related to at the Beginning of the Period $ 2,499 $ 2,219 Regulatory Matters and Nuclear Operations. Service Cost 48 43 Interest Cost 164 162 Actuarial Loss 201 235 NOTE 14 - Retirement Benefits and Benefits Paid (159) (160)

Trusteed Assets Plan Amendments (8)

Projected Benefit Obligation QUALIFIED PENSION PLAN BENEFITS at the End of the Period S 2,745 $ 2,499 We have defined benefit retirement plans for eligible union and Plan Assets at Fair Value nonunion employees., Prior to December 31, 2001, we had three at the Beginning of the Period 5 1,845 $ 2,183 separate defined benefit retirement plans. Effective December 31, Actual Return on Plan Assets 440 (213) 2001, two of the defined benefit retirement plans merged into one Company Contributions 222 35 plan. The plans are noncontributory, cover substantially all. Benefits Paid (159) (160) employees and provide retirement benefits based on the employees' Plan Assets at Fair Value years of benefit service, average final compensation and age at at the End of the Period $ 2,348 $ 1,845 retirement. Certain nonrepresented employees are covered under Funded Status of the Plans $ (397) $ (654) cash balance benefits based on annual employer contributions and Unrecognized interest credits. Our policy isto fund pension costs by contributing Net loss 1,010 1,080 the minimum amount required by the Employee Retirement Income Prior service cost 41 54 Security Act (ERISA) and additional amounts we deem appropriate. Net Amount Recognized S 654 $ 480 Amount Recorded as:

Net pension cost (credit) for the years ended December 31 includes Prepaid Pension Assets $ 181 $ 172 the following components: Accrued Pension Liability (287) (531)

Regulatory Asset 572 r(n Millions) 2003 2002 2001 Accumulated Other Comprehensive Loss 147 785 ServiceCost $ 48 $ 43 $ .40 Intangible Asset 41 54 Interest Cost 164 162 140 $ 654 $ 480 Expected Return on Plan Assets (211) (223) : (193)

Amortization of Assumptions used in determining the projected benefit obligation Net loss 38 2 -

at December 31 are listed below:

Prior service cost 8 9 10 Net transition asset - (2) (5) 2003 2002 2001 Special Termination Benefits (Note 3) - - 167 Discount rate 6.25 % 6.75% 7.25%

Net Pension Cost (Credit) S 47 $ (9)$ 159 Annual increase infuture compensation levels 4.0% 4.0% 4.0%

The following table reconciles the obligations, assets and funded status of the plans as well as the amounts recognized as prepaid pension cost or pension liability in the consolidated statement of Assumptions used in determining net pension costs at December 31 financial position at December 31: are listed below:

2003 2002 2001 Discount rate 6.75% 7.25% 7.50%

Annual increase infuture compensation levels 4.0 % 4.0% 4.0%

Expected long-term rate of return on Plan assets 9.0 % 9.5% 9.5 %

We employ a consistent formal process indetermining the long-term the non represented plan), an intangible asset of $54 million and rate of return for various asset classes. We evaluate input from our other comprehensive loss of $785 million ($510 million after tax).

consultants, including their review of historic financial market risks In2003, Detroit Edison reclassified $572 million of other and returns and long-term historic relationships between the asset comprehensive loss related to the minimum pension liability to classes of equities, fixed income and other assets, consistent with a regulatory asset.

the widely accepted capital market principle that asset classes with higher volatility generate a greater return over the long-term. At December 31, 2003 the minimum pension liability was $760 million, Current market factors such as inflation, interest rates, asset class intangible asset was $41 million, regulatory asset was $572 million, risks and asset class returns are evaluated and considered before other comprehensive loss was $147 million ($96 million after tax) long-term capital market assumptions are determined. The long- and deferred taxes were $51 million.

term portfolio return is also established employing a consistent formal process, with due consideration of diversification, active We plan on making a $170 million contribution of DTE Energy investment management and rebalancing. Peer data is reviewed to common stock to our defined benefit retirement plans inthe first check for reasonability. quarter of 2004. A contribution is not required under ERISA.

We employ a total return investment approach whereby a mix of We also sponsor defined contribution retirement savings plans.

equities, fixed income and other investments are used to maximize Participation in one of these plans is available to substantially all the long-term return of plan assets consistent with prudent levels represented and nonrepresented employees. We match employee of risk. The intent of this strategy isto minimize plan expenses over contributions up to certain predefined limits based upon eligible the long-term. Risk tolerance is established through consideration compensation, the employee's contribution rate and years of of future plan cash flows, plan funded status, and corporate financial credited service. The cost of these plans was $26 million in 2003, considerations. The investment portfolio contains adiversified $25 million in 2002 and $26 million in 2001.

blend of equity, fixed income and other investments. Furthermore, equity investments are diversified across U.S and non-U.S. stocks, NONQUALIFIED PENSION BENEFIT PLANS growth and value investment styles, and large and small market capitalizations. Other assets such as private equity and absolute We maintain supplemental nonqualified, noncontributory, retire-return funds are used judiciously to enhance long term returns ment benefit plans for selected management employees. These while improving portfolio diversification. Derivatives may be used plans provide for benefits that supplement those provided by DTE to gain market exposure in an efficient and timely manner; however, Energy's other retirement plans.

derivatives may not be used to leverage the portfolio beyond the Net pension cost for the years ended December 31 includes the market value of the underlying investments. Investment risk is following components:

measured and monitored on an ongoing basis through annual liability measurements, periodic asset/liability studies, and quarterly (inMillions) 2003 2002 2001 investment portfolio reviews. Service Cost 2 $ 1$ -I Interest Cost 4 3 2 Our Plans' weighted-average asset allocations by asset category at Amortization of December 31 are as follows: Net loss I 1 20M3 2002 Prior service cost - 1 1 Equity Securities 67% 62% Special Termination Benefits (Note 3 - - 6 Debt Securities. 27 31 Net Pension Cost S 7 $ 6$ 10 Other 6 7 100% 100% The following table reconciles the obligations, assets and funded status of the plans as well as the amounts recognized as an :

Our Plans' weighted-average asset target allocations by asset accrued pension liability in the consolidated statement of financial.

category at December 31, 2003 are as follows: position at December 31:

Equity Securities 65%

Debt Securities - 28 Other 7 -

100%

InDecember 2002, we recognized an additional minimum pension liability as required under SFAS No. 87, 'Employers'Accounting for Pensions." An additional pension liability may be required when the accumulated benefit obligation of the plan exceeds the fair value of plan assets. Under SFAS No. 87, we recorded an additional minimum pension liability of $839 million, ($531 million after netting the previously recognized prepaid pension asset associated with i I I

I,(if M I

(inMillions) 2003 2002 Net postretirement cost for the years ended December 31 includes Measurement Date December31 December31 the following components:

Accumulated Benefit Obligation at the End of the Period . 57 $ 49 (inMillions) 2003 2002 2001 Projected Benefit Obligation atthe Service Cost $ 37 $ 30 $ 27 Beginning of the Period $ 50$ -42 Interest Cost 87 78 67 Service Cost 2 1- Expected Return on Plan Assets (47) (59) (57)

Interest Cost 4 3 Amortization of Actuarial Loss 6 7 Net loss 31 3 1 Benefits Paid (3) (3) Prior service cost (3) (1) _

Projected Benefit Obligation at the. Net transition obligation 13 19 20 End of the Period $ 59 $ 50 Special Termination Benefits (Note 3) _ - 46 Plan Assets at Fair Value at the Net Postretirement Cost $ 118 $ 70 $ 104 Beginning of the Period $ - $ -

Company Contributions 3 3 Cmnyfit Contributions The following table reconciles the oblicgations, assets and funded Benefits Paid (3) (3) 1 status of the plans including amounts recorded as accrued Pand Assets athFairiVale . .postretirement cost inthe consolidated statement of financial End of the Period $ - $ - psto tDcme 1 Funded Status of the Plans $ (59) $ (50) position at December 31 Unrecognized i (inMillions) 2003 2002 Net loss 18 12 Measurement Date December31 December 31 Prior service cost 3 3 Accumulated Postretirement Benefit Net Amount Recognized $ (38)$ (35) Obligation at the Beginning of the Period $ 1,494$ 1,127 Amount Recorded as: Service Cost 37 30 Accrued Pension Liability $ (58) $ (51) Interest Cost 87 78 Regulatory Asset 13 - Actuarial Loss 162 326 Accumulated Other Comprehensive Loss 4 13- Plan Amendments (126) -

Intangible Asset 3 3 Benefits Paid (72) (67)

S (38) $ (35) Accumulated Postretirement Benefit Obligation at the End of the Period S 1582 $ 1,494 Assumptions used in determining the projected benefit obligation Plan Assets at Fair Value at the at December 31 are listed below: Beginning of the Period $ 537 $ 624 Actual Return on Plan Assets 114 (60) 2003 2002 2001 Company Contributions 33 Discount rate 6.25% 6.75% 7.25% Benefits Paid (65) (60)

Annual increase in future Plan Assets at Fair Value at the compensation levels 4.0 % 4.0% 4.0% End of the Period $ 586 $ 537 Funded Status of the Plans $ (996) $ (957)

Assumptions used in determining net pension costs at December 31 Unrecognized are listed below: Net loss 705 641 Prior service cost (27) (7) 2003 2002 2001 Net transition obligation 74 191 Discount rate 6.75 % 7.25 % 7.50 % Accrued Postretirement Liability $ (244)$ (132)

Annual increase infuture compensation levels 4.0 % 4.0% 4.0%

Assumptions used in determining the projected benefit obligation at December 31 are listed below: I :

At December 31, 2003, under SFAS No. 87, the minimum pension liability was $20 million, intangible asset was $3million, regulatory 2003 2002 2001 asset was $13 million, other comprehensive loss was $4million Discount rate 6.25 % 6.75 % 7.25%

($3 million after tax) and deferred taxes were $1 million.

Assumptions used in delLermining benefit costs at December 31 are OTHER POSTRETIREMENT BENEFITS listed below:

We provide certain postretirement health care and life insurance 2003 2002 2001 benefits for employees who become eligible for these benefits D while working for us. 6.75 % 7.25% 7.50%

Expected long-term rate of return on Plan assets 9.0 % 9.5% 9.5%

III I Il

Benefit costs were calculated assuming health care cost trend Our Plans' weighted-average asset allocations by asset category at rates beginning at 9.0% for 2004 and decreasing to 5.0% in 2009 December 31 are as follows:

and thereafter for persons under age 65 and decreasing from 8.0%

to 5.0% for pers'ons age 65 and over. A one-percentage-point 2003 - 2002 increase in health care cost trend rates would have increased the EquitySecurities 66%' .61%

total service cost and interest cost components of benefit costs Debt Securities - 30 35 by $18 million. The accumulated benefit obligation would have Other 4 4 increased by $148 million at December 31, 2003. A one-percentage- 100% 100%

point decrease inthe health care cost trend rates would have decreased the total service and interest cost components of benefit Our Plans' weighted-average asset target allocations by asset costs by $16 million and would have decreased the accumulated category at December 31,2003 are as follows: '

benefit obligation by $132 million at December 31, 2003.

Equity Securities 65%

The Company amended its postretirement health care and life Debt Securities 28 insurance plans to reduce benefits, modify eligibility criteria and Other 7 increase retiree co-pays. The changes reduced the postretirement :- 100%

benefit obligation by $126 million, the 2003 postretirement costs by $17 million and the expected 2004 postretirement costs by.

We made a $40 million cash contribution to our postretirement

$29 million.

health care and life insurance plans inJanuary 2004.'

We employ aconsistent formal process indetermining the long-term rate of return for various asset classes. We evaluate input from our InDecember 2003, the Medicare Prescription Drug, Improvement consultants, including their review of historic financial market risks'. and Modernization Act was signed into law. This'Act provides for a and returns and long-term historic relationships between the asset federal subsidy to sponsors' of retiree health care benefit plans classes of equities, fixed income and other assets, consistent with that provide a benefit that is at least actuarially equivalent to the the widely accepted capital market principle that asset classes benefit established by law. We have elected to defer the provisions with higher volatility generate a greater return over the long-term. of the Act, and our measures of the accumulated postretirement Current market factors such as inflation, interest rates, asset class benefit obligation or net periodic postretirement benefit cost do not risks and asset'class returns are evaluated and considered before reflect the effects of the Act, if any. Specific authoritative guidance, long-term capital market assumptions are determined. The long-term when issued by the FASB, could require us to re-determine the impact of the Act and change previously reported information.

portfolio return isalso established employing a consistent formal process, with due consideration of diversification, active investment management and rebalancing. Peer data is reviewed to check Grantor Trust for reasonability. MichCon maintains a Grantor Trust that invests in life insurance contracts and income securities. Employees and retirees have no-We employ a total return investment approach whereby a mix of right, title or interest in the assets of the Grantor Trust, and equities, fixed income and other investments are used to maximize MichCon can revoke the trust subject to providing the MPSC the long-term return of plan assets consistent with prudent levels with prior notification. We record our investment at market value of risk. The intent of this strategy isto minimize plan expenses over and account for unrealized gains and losses in the Consolidated the long-term. Risk tolerance is established through consideration Statement of Operations.

of future plan cash flows, plan funded status, and corporate financial considerations. The investment portfolio contains a diversified-blend of equity, fixed income and other investments. Furthermore, NOTE 15 - Stock-Based Compensation equity investments are diversified across U.S and non-U.S. stocks, The DTE Energy Company 2001 Stock Incentive Plan permits the growth and value investment styles, and large and small market grant of incentive stock options, non-qualifying stock options, stock capitalizations. Other assets such as private equity and absolute awards, performance shares and performance units. A maximum return funds are used judiciously to enhance long term returns of 18 million shares of common stock may be issued under the while improving portfolio diversification. Derivatives may be used plan. Participants in the plan includ-eour employees and Board' to gain market exposure in an efficient and timely manner; however, members. As of December 31, 2003, no performance units have derivatives may not be used to leverage the portfolio beyond the been granted under the plan.

market value of the underlying investments. Investment risk is measured and monitored on an ongoing basis through annual Prior to 2001, stock options, stock awards and performance shares liability measurements, periodic asset/liability studies, and were issued under the Long-Term Incentive Plan adopted in 1995.

quarterly investment portfolio reviews.

OPTIONS , -:

Options are exercisable at a rate according to the terms of the individual stock option award agreements. The options will expire 10 years after the date of the grant. The option exercise price 111IMIM I1IA MI I

equals the fair value of the stock on the date that the option was including the right to receive dividends and vote the shares; provided, granted. Stock option activity was as follows: that during such period (i)a participant may not sell, transfer, pledge, exchange or otherwise dispose of shares granted pursuant to a Weighted stock award; (ii) we shall retain custody of the certificates evidencing Number Average of Exercise shares' granted pursuant to a stock award; and (iii) the participant

-Options Price will deliver to us a stock power with respect to each stock award.

Outstanding at January 1,2001 (442,431 exercisable) 2.982,225 $ 33.69 The stock awards are recorded at cost that approximates the Granted 2,775,341 $ 42.74 market value on the date of grant. We account for stock awards Exercised (402,442) $ 32.31 as unearned compensation, which isrecorded as a reduction to Canceled (73,500) $ 36.26 common stock. The cost is amortized to compensation expense Outstanding at December 31, 2001 over the vesting period. Stock award activity for the years ended (1,678,870 exercisable) 5,281,624 $ 38.51 December31 was:

Granted 1,334,370 $ 42.08 2003 2002 2001 Exercised (678,715) $ 34.64 Restricted common shares Canceled (456,684) $ 38.74 awarded 102,060 113,410 247,640 Outstanding at December 31, 2002 Weighted average market price (2,285,323 exercisable) 5,480,595 $ 39.87 of shares awarded $ 41.39 $ 42.92 $ 44.35 Granted 1,654,879 $ 40.56 Compensation cost charged Exercised (329,528) S 35.88 against income (inthousands) $ 6,366 $ 4,101 $ 2,484 Canceled (152,824) $ 42.67 Outstanding at December 31, 2003 PERFORMANCE SHARE AWARDS (3,506,038 exercisable at a weighted average exercise price of $39.14) 6,653,122 S 40.18 Under the plan, performance shares are awards stated with reference to a specified number of shares of common stock that entitles the The range of exercise prices for options outstanding at December holder to receive a cash payment or shares of common stock or a 31, 2003, was $27.62 to $46.74. The number, weighted average combination thereof. The final value of the award isdetermined by exercise price and weighted average remaining contractual life of the achievement of certain performance objectives, as defined in options outstanding were as follows: the plan. The awards vest as of the end of a specified period.

Beginning with the grant date, we account for performance share Weighted Weighted Average awards by accruing an amount based on the following: (i)the number Range of Number of Average Remaining of shares expected to be awarded based on the probable achievement Exercise Prices Options Exercise Price Contractual Life of certain performance objectives, (ii)the market value of the shares,

$ 27.62 - $ 38.04 1,253,366 $ 31.63 - 5.88 years and (iii) the vesting period. For 2003, 2002 and 2001, we accrued

$ 38.60 - $ 42.44 3,657,880 $ 41.21 . 8.01 years compensation expense related to performance share awards totaling

$ 42.60 - $ 44.54 810,826 $ 42.69 7.37 years $5.5 million, $3.6 million and $1.2 million, respectively.

$ 45.28 - $ 46.74 931,050 $ 45.45 7.47 years 6.653.122 . $40.18 7.45 years During the applicable restriction period, the recipient of a performance share award has no shareholder rights. However, recipients will We apply APB Opinion 25, 'Accounting for Stock Issued to be paid an amount equal to the dividend equivalent on such Employees.' Accordingly, no compensation expense has been shares Performance share awards are nontransferable and are recorded for options granted. As required by SFAS No. 123, subject to risk of forfeiture. As of December 31, 2003, there were

'Accounting for Stock-Based Compensation,' we have determined 617,404 performance share awards outstanding.

fair value for these options at the date of grant using a Black-Scholes based option pricing model and the following assumptions:

NOTE 16 - Segment and Related Information 2003 2002 . 2001 Beginning in 2002, we realigned our internal and external financial Risk-free interest rate 2.93 % 5.33% 5.40% reporting structure into three strategic business units (Energy Dividend yield 4.97 % 4.90% 4.73% Resources, Energy Distribution and Energy Gas) that have both Expected volatility 20.89 % 19.79% 19.78% regulated and non-regulated operations. The balance of our business consists of Corporate & Other. Based on this structure we set Expected life 6 years 6years 10years strategic goals, allocate resources and evaluate performance.

This results in the following nine reportable segments:

Fair value per option $ 4.78 $ 6.25 $ 8.81 STOCK AWARDS Under the plan, stock awards are granted and restricted for varying periods, which currently do not exceed four years. Participants have all rights of a shareholder with respect to a stock award, II I

ENERGY RESOURCES The income tax provisions or benefits of DTE Energy's subsidiaries are determined on an individual company basis and recognize the Regulated- Power Generation operations include the power tax benefit of Section 29 tax credits and net operating losses.

generation services of Detroit Edison, the company's electric The subsidiaries record income tax payable to or receivable from utility. Electricity isgenerated from Detroit Edison's numerous DTE Energy resulting from the inclusion of its taxable income or fossil plants or its nuclear plant and sold throughout loss in DTE Energy's consolidated tax return. Inter-segment revenues Southeastern Michigan to residential, commercial, industrial and are not material. Financial data of the business segments follows:

wholesale customers.

Non-regulated Energy Services is comprised of various businesses that develop, acquire and manage energy-related assets and services. Such projects include coke production, synfuels production, on-site energy projects and merchant generation facilities.

Energy Marketing & Trading consists of the electric and gas marketing and trading operations of DTE Energy Trading Company and the natural gas marketing and trading operations of DTE Enterprises, which was acquired as part of the MCN Energy acquisition. Energy Marketing & Trading enters into forwards, futures, swaps and option contracts as part of its trading strategy.

Other non-regulated operations consist of businesses involved in coal services and landfill gas recovery.

ENERGY DISTRIBUTION Regulated- Power Distribution operations include the electric distribution services of Detroit Edison. Energy Distribution distributes electricity generated by Energy Resources to Detroit Edison's 2.1 million residential, commercial and industrial customers.

Non-regulated operations include businesses that market and distribute a broad portfolio of distributed generation products, provide application engineering, and monitor and manage system operations.

ENERGY GAS Regulatedoperations include gas distribution services provided by MichCon, the company's gas utility that purchases, stores and distributes natural gas throughout Michigan to 1.2 million residential, commercial and industrial customers.

Non-regulated operations include the production of gas and the gathering, processing and storing of gas. Certain pipeline and storage assets are primarily supported by the Energy Marketing &

Trading segment.

CORPORATE & OTHER Corporate & Other includes administrative and general expenses, and interest costs of DTE Energy corporate that have not been allocated to the regulated and non-regulated businesses' Corporate & Other also includes various other non-regulated operations, including investments in new emerging energy technologies.

I III . , 'dI I.

(inMillions) Depreciation, Operating Depletion & Interest Income Net Total Capital 2003 Revenue Amortization Expense Taxes Income Assets Goodwill Expenditures Energy Resources Regulated -

Power Generation $ 2,448 $ 224 $ 157 $ 135 $ 235 $ 7,216 $ 406 $ 340 Non-Regulated Energy Services 929 84 - 20 (249) 199 1,644 41 22 Energy Marketing &Trading 764 2 2 20 45 1,067 17 6 Other 297 7 2 (17) (2) 128 4 -11 Total Non-Regulated 1,990 93 - 24 (246) 242 2,839 62 39 Total Energy Resources 4,438 317 181 (111) 477 10,055 468 379 Energy Distribution Regulated-Power Distribution 1,247 249 127 10 17 5,333 796 240 Non-Regulated 39 2 - (8) (15) 65 12 1 1,286 251 127 2 2 5,398 808 241 Energy Gas Regulated - Gas Distribution 1,498 101 58 - 29 3,035 776 99 Non-Regulated 90 18 8 14 29 518 15 28 1,588 119 66 14 58 3,553 791 127 Corporate & Other 12 - 219 (28) (57) 2,383 - 4 Reconciliation & Eliminations (283) - (47) - - (636) - -

Total from Continuing Operations $ 7,041 $ 687 $ 546 $ (123) 480 20,753 2,067 751 Discontinued Operations (Note 3) 68 Cumulative Effect of Accounting Changes (27)

Total $ 521 $20,753 $ 2,067 $ 751 (inMillions) Depreciation, Operating Depletion & Interest Income Net Total Capital 2002 Revenue Amortization Expense Taxes Income Assets Goodwill Expenditures Energy Resources Regulated -

Power Generation $2,711 $ 331 $ 184 $ 120 $ 241 $ 7,334 $ 406 $ 395 Non-Regulated Energy Services 645 81 19 (268) 182 1,536 41 130 Energy Marketing &Trading 681 3 15 13 25 822 17 Other 102 9 4 (19) 7 256 4 8 Total Non-Regulated 1,428 93 38 (274) 214 2,614 62 138 Total Energy Resources 4,139 424 222 (154) 455 9,948 468 533 Energy Distribution Regulated-Power Distribution 1,343 246 127 58 111 4,154 796 290 Non-Regulated 39 2 1 (9) (16) 60 12 2 1,382 248 128 49 95 4,214 808 292 Energy Gas Regulated-Gas Distribution 1,369 104 57 36 66 2,871 776 93 Non-Regulated 87 19 6 14 26 504 16 32 1,456 123 63 50 92 3,375 792 125 Corporate & Other 16 - 232 (32) (56) 2,378 - 24 Reconciliation & Eliminations (264) (58) (76) 3 - (548) -

Total from Continuing Operations $ 6,729 $ 737 $ 569 $ (84) 586 19,367 2,068 974 Discontinued Operations (Note 3) -

46 618 -

44 -

10 -

Total $ 632 $19,985 $ 2,112 $ 984

$ 984 I ~mm

(inMillions) Depreciation, Operating Depletion & Interest Income Net Total Capital 2001 Revenue Amortization Expense Taxes Income Assets Expenditures Energy Resources Regulated -

Power Generation $ 2,788 $ 385 $ 181 $ 58 $ 139 $ 7,400 $ 348 Non-Regulated Energy Services 447 85 25 (173) 115 1,185 257 Energy Marketing & Trading 554 2 13 24 44- 835 -

Other 143 10 5 (15) 6 206 -

Total Non-Regulated 1,144 97 43 (164) 165 2,226 257 Total Energy Resources 3,932 482 224 (106) 304 9,626 605 Energy Distribution Regulated - Power Distribution 1,256 246 125 26 97 4,073 325 Non-Regulated 21 1 1 (6) (110) 66 5 1,277 247 126 20 87 4,139 330 Energy Gas Regulated - Gas Distribution 615 61 34 (49) (38) 2,886 66 Non-Regulated 51 12 7 5 11 486 23 666 73 41 (44) (27) 3,372 89 Corporate & Other 11 29 127 (28) - (55) 2,324 50 Reconciliation & Eliminations (99) (49) (36) 39 - (449)

Total from Continuing Operations $ 5,787 $ 782 $ 482 $ (119) 309 19,012 1,074 Discontinued Operations (Note 3)- 20 575 22 Cumulative Effect of Accounting Changes 3 Total S 332 $19,587 $1,096 I I , I' ' I II

NOTE 17 - Supplementary Quarterly Financial Information (Unaudited)

Quarterly earnings per share may not total for the years, since quarterly computations are based on weighted average common shares outstanding during each quarter. In February 2003, we sold ITC which has been accounted for as a discontinued operation (Note 3).

First Second Third Fourth (inMillions, except per share amounts) :Quarter Quarter Quarter Quarter Year 2003 Operating Revenues $ 2,095 $ 1,600 $ 1,654 $ 1,692 $ 7,041 Operating Income $ 217 $ 71 $ 232 S 227 $ 747 Net Income (Loss)

From continuing operations $ 108 $ (37) $ 180 $ 229 $ 480 Discontinued operations 74 (2) (4) - 68 Cumulative effect of accounting changes (27) - _ _ (27)

Total $ 155 $ (39) S 176 $ 229 S 521 Basic Earnings (Loss) per Share From continuing operations $ .65 S (.22) S 1.07 $ 1.36 $ 2.87 Discontinued operations .44 (.01) (.02) - .41 Cumulative effect of accounting changes - (.17) _ _ _ (.17)

Total - $ .92 $ (.23) $ 1.05 $ 1.36 S 3.11 Diluted Earnings (Loss) per Share From continuing operations $ .64 $ (.22) $ 1.06 $ 136 $ 285 -

Discontinued operations .44 (.01) (.02) - .40 Cumulative effect of accounting changes (.16) - - - (.16)

Total S .92 S (.23) S 1.04 1.36 $ 3.09 2002 Operating Revenues $ 1,894 $ 1,474 $ 1,615 $ 1,746 $ 6,729 iOperating Income $ 333 $ 180 $ 235 $ 246 $ 994 Net Income From continuing operations $ 192 $ 61 $ 139 $ 194 $ 586 Discontinued operations 8 7 22 9 46 Total $ 200 $ 68 $ 161 $ 203 $ 632 Basic Earnings per Share From continuing operations $ 1.20 $ .38 $ .83 $ 1.17 $ 3.57 Discontinued operations .05 .04 .13 .05 .28 Total $ 1.25 $ A2 $ .96 $ 1.22 $ 3.85 Diluted Earnings per Share From continuing operations $ 1.19 $ .38 $ .83 $ 1.16 $ 3.55 Discontinued operations .05 .04 .13 .05 .28 Total $ 1.24 $ .42 $ .96 $ 1.21 $ 3.83 Jr I p I

DTE ENERGY COMPANY Statistical Review I (Dollars inMillions, Except Common Share Data) 2003 2002 2001 2000 Operating Revenues Regulated $ 5,193 $ 5,423 $ 4,659 $ 4,129 Non-regulated 1,848 1,306 1,128 509 Total S 7,041 $ 6,729 $ 5,787 $ 4,638 Net Income Regulated $ 281 $ 418 $ 198 $ 427 Non-regulated 199 168 111 41 480 586 309 468 Discontinued Operations 68 46 20 Cumulative Effect of Accounting Changes (27) - 3

$ 521 $ 632 S 332 S 468 Diluted Earnings per Share Regulated S 1.67 $ 2.53 $ 1.29 $ 2.99 Non-regulated 1.18 1.02 0.72 0.28 2.85 3.55 2.01 3.27 Discontinued Operations .40 .28 .13 -

Cumulative Effect of Accounting Changes (.16) - .02 -

S 3.09 $ 3.83 $ 2.16 $ 3.27 Electric Utility Deliveries MillionsofkMh) 5Z792 53,702 51,137 52,234 Electric Utility Customers at Year End (Thousands) Z132 2,136 2,125 2,110 Gas Utility Deliveries (Bcf(10) 909 837 917 945 Gas Utility Customers at Year End (Thousands)(1) 1,249 1,267 1,235 1,235 Financial Position at Year End Net property (2) $ 10,324 S 10,542 $ 10,255 $ 8,081 Total assets (2) $ 20,753 S 19,985 $ 19,587 $ 13,350 Long-term debt including capital leases $ 7,669 $ 7,803 $ 7,928 $ 4,039 Total shareholders' equity $ 5,287 $ 4,565 $ 4,589 $ 4,009 Common Share Data Dividends declared per share $ Z06 $ 2.06 $ 2.06 $ 2.06 Average shares outstanding-diluted (millions) 168 165 154 143 Book value per share S 31.36 $ 27.26 $ 28.48 $ 28.14 Market price: High S 49.50 $ 47.70 $ 47.13 S 41.25 Low $ 34.00 $ 33.05 $ 33.13 $ 28.44 Year end S 39.40 $ 46.40 $ 41.94 S 38.94 Miscellaneous Financial Data Cash flowfrom operations S 950 $ 996 $ 811 $ 1,015 Capital expenditures $ 751 $ 984 $ 1,096 $ 749 Employeesatyearend 11,099 11,095 11,030 9,144 (1)Gas Utility data shown priorto May 2001 is presented for informational purposes only. The acquisition of MCN Energy became effective on May 31, 2001.

(2)Inconjunction with adopting SFAS No. 143, we reclassified previously accrued asset removal costs related to our regulated operations, which had been previously netted against accumulated depreciation, to an asset removal cost liability for the years 1999 through 200Z Amounts for years prior to 1999 are not available.

1999 1998 1997 1996 1995 1994 1993

$ 4,047 $ 3,902 $ 3,657 $ 3,642 S 3,64 $ 3,519 $ 3,555 452 272 107 . 3 - 2

$ 4,499 S 4,174 $ 3,764 $ 3,645 S 3,636 $ 3,519 $ 3,555

$ 434 $ 412 S 405 $ 312 $ 406 $ 390 $ 491 49 31 12 .(3) 483 4943 417 309 406 390 491

$ 483 $ 443 $ 417 $ 309 $ 406 $ 390 $ 491

$ 3.00 $ 2.83 $ 2.79 $ 2.15 $ 2.80 $ 2.67 $ 3.34.

0.33 0.22 .09 (.02) - - -

3.33 3.05 2.88 2.13 2.80 2.67 3.34 S 3.33 $ 3.05 $ 2.88 $ 2.13 $ 2.80 $ 2.67 $ 3.34 55,524 54,913 50,642 48,453 48,942 46,132 46,576 2,089 2,068 2,051 2,025 2,002 1,980 1,964 866 850 941 895 730 667 637 1,220 1,206 1,193 1,183 1,173 1,155 1,142 S 7,853

$ 13,021

$ 4,091 $ 4,323 $ 3,914 S 3,894 $ 3,884 $ 3,951 $ 3,972

$ 3,909 $ 3,698 $ 3,706 $ 3,588 S 3,763 $ 3,706 $ 3,677

$ 2.06 $ 2.06 $ 2.06 $ 2.06 $ 2.06 $ 206 $ 2.06 145 145 145 145 145 146 147

$ 2675 $ 25.49 $ 24.51 $ 23.69 $ 23.62 $ 22.89 $ 22.34

$ 44.69 $ 49.25 S 34.75 $ 37.25 $ 34.88 $ 30.25 $ 37.13

$ 31.06 $ 33.50 $ 26.13 $ 27.63 $ 25.75 $ 24.25 $ 29.88 S 31.63 $ 43.06 $ 34.69 $ 32.38 34.50 $ 26.13 $ 30.00 1$,084 $ 834 $ 905 $ 1,079 $ 913 $ 923 $ 1,110 7$

39 $ 589 $ 484 $ 531 $ 454 $ 366 $ 396 8,886 8,781 8,732 8,526 8,340 8,494 8,919 II. iI I

Words Our Industry Uses Coke and Coke Battery Power Supply Cost Recovery (PSCR)

Raw coal is heated to high temperatures in Mechanism ovens to drive off impurities, leaving a carbon residue called coke. Coke is combined with A power supply cost recovery mechanism iron ore to create a high metallic iron that is authorized by the MPSC that allowed Detroit used to produce steel. A series of coke ovens Edison to recover through rates its fuel, configured in a module is referred to as fuel-related and purchased power expenses.

a battery. The clause was suspended under Michigan's restructuring legislation signed into law June 5,2000, which lowered and froze electric Customer Choice customer rates. The clause was reinstated by The customer choice programs are statewide the MPSC effective January 1,2004.

initiatives giving customers in Michigan the option to choose alternative suppliers for Section 29 Tax Credits electricity and gas. Tax credits as authorized under Section 29 of the Internal Revenue Code that are designed Distributed Generation (DG) to stimulate investment in and development of Electric energy produced at or close to the alternate fuel sources.

point of use, in contrast to central station generation which generally produces electricity Securitization at large power plants and transmits and distributes power over long distances. DG Detroit Edison financed specific stranded costs includes fuel cells, small gas turbine engines at lower interest rates through the sale of rate called micro- and mini-turbines, and other reduction bonds by awholly owned special devices capable of producing up to two purpose entity, the Detroit Edison Securitization megawatts of power. Funding LLC.

Gas Cost Recovery (GCR) Mechanism Stranded Costs A gas cost recovery mechanism authorized by Costs incurred by utilities in order to serve the MPSC that was reinstated by MichCon in customers in a regulated environment that are not January 2002, permitting MichCon to pass the expected to be recoverable if customers switch to alternative suppliers of electricity and gas.

cost of natural gas to its customers.

Synfuels The fuel produced through a process involving chemically modifying and binding particles of coal. Synfuels are used for power generation and coke production.

II, II

Other information about DTE Energy Market for the Company's Common Equity and Annual Meeting of Shareholders Related Shareholder Matters The 2004 Annual Meeting of DTE Energy Shareholders will DTE Energy's common stock is listed on the New York be held at 10 a.m., Detroit time, Thursday, April 29, 2004, Stock Exchange and the Chicago Stock Exchange at the DTE Energy Building, 660 Plaza Drive, Detroit (symbol DTE). The following table indicates the reported high and low sales prices of DTE Energy common stock Corporate Address on the composite tape of the New York Stock Exchange DTE Energy, 2000 2nd Ave., Detroit, MI 48226-1279 and dividends paid per share for each quarterly period Telephone: 313.235.4000 www.dteenergy.com during the past two years:

Dividends Independent Auditors Paid Calendar Quarter High Low Per Share Deloitte & Touche LLP 2003 First $ 49.50 $ 38.51 $ 0.515 600 Renaissance Center, Suite 900, Detroit, Ml 48243-1704 Second 44.95 38.52 0.515 Third 38.98 34.00 0.515 Form 10-K Fourth 39.76 35.12 0.515 We will provide without charge to our shareholders copies of Form 10-K, Securities and Exchange Commission 2002 First $ 45.75 $ 39.65 $ 0.515 Annual Report. Written requests should be directed to:

Second 47.70 42.65 0.515 Third 44.56 33.05 0.515 Susan M. Beale Fourth 46.90 38.20 0.515 Vice President and Corporate Secretary DTE Energy, 2000 2nd Ave., Detroit, Ml 48226-1279 As of Dec. 31, 2003, 168,606,522 shares of the company's or www.dteenergy.comlinvestors common stock were outstanding. These shares were held by a total of 105,173 shareholders. Transfer Agent Send certificates for transfer and address changes to:

Bank of New York, Receive and Deliver Department Distribution of Ownership of DTE Energy RO. Box 11002, Church Street Station, New York, NY 10286 Common Stock as of Dec. 31, 2003: or refer to the Bank of New York's stock transfer Type of Owner Owners Shares Web site: www.stockbny.com Individuals 63,238 21,515,986 Joint Accounts 39,844 16,374,278 Registrar of Stock Trust Accounts 940 664,284 Address shareholder inquiries to:

Nominees 18 129,416,201 Bank of New York, Shareholder Relations Department Institutions/Foundations 147 71,162 RO. box 11258, Church Street Station, New York, NY 10286 Brokers/Security Dealers 47 27,804 or e-mail inquires to: shareowner-svcs~bankofny.com Others 939 536,807 Total 105,173 168,66,522 Other Shareholder Information As a service to shareholders of record, DTE Energy offers State and Country Owners Shares direct deposit of dividend payments through the Bank of Michigan 54,001 21,431,747 New York. Payments can be electronicallytransferred Florida 6,238 2,732,807 directly to the bank or savings and loan account of choice California 5,239 1,792,832 on the payment date. Please write to the address below, New York 4,201 130,830,516 or call 866.388.8558 to receive an authorization form to Illinois 3,987 1,403,979 request direct deposit of dividend payments.

Ohio 3,280 1,087,581 44 Other States 27,780 9,187,757 Bank of New York Foreign Countries 447 139,303 Shareholder Relations Department 168,606522 P.O. box 11258, Church Street Station, New York, NY 10286 Total 105,173 or e-mail inquires to: shareowners~bankofny.com 02004 DTE Energy Company, DTE Energy is the owner of the Printed by Case-Hoyt, all rights reserved. "Head/Corona" logo. DTE Energy or Its a St. Ives Group Company DTE affiliates are the owners of various other Rochester, New York.

registered and unregistered trademarks.

NYSE III I 'I'

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Tell us what you think ... DTE Energy On a scale of 1 (poor) to 5 (excellent), please rate the following items: How much time did you spend looking

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What format do you prefer for the What section of the annual report did you DTE Energy Annual Report? (check one) find most useful? (check as manyas apply) - Traditional printed document (like the 2003 book)

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_ Management's Discussion (p.21-37)

_ CD/print hybrid (print version of editorial section,

_ Financial statements (p.39-45) CD of financials)

_ Notes (p.44-73) Electronic (annual report on DTE Energy Web site,

_ Glossary (p.76) no printed piece)

_ Other information for shareholders (p.77) Are you a current shareholder? _-Yes _No Other comments:

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NO POSTAGE NECESSARY IF MAILED IN THE BUSINESS REPLY MAIL UNITED STATES FIRST-CLASS MAIL PERMIT NO. 61 DETROIT Ml POSTAGE WILL BE PAID BYTHE ADDRESSEE ATTN WRITING RESOURCES 1571 WCB DTE ENERGY 2000 2ND AVE.

DETROIT Ml 48226-9886 IiIIiIIiIIIiIIIIIiIIIiIItIIIIIIIIIIiIiIIIIIIIiIIIiII

NRC-04-0027, 2003 Annual Financial Report for the DTE Energy Company

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