Text

Annual Financial Report
	ML051240042
Person / Time
Site:	Fermi
Issue date:	04/27/2005
From:	Peterson N; Detroit Edison
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	NRC-05-0040
	Download: ML051240042 (83)
	v • d • e

Fermi 2 640aNortEDwxie Hwy., Newport, MI 48166 Detroit Edison 1IF 10 CFR 50.71(b)

April 27, 2005 NRC-05-0040 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 CFR 50.71(b), please find enclosed the 2004 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) 586-4258.

Sncr n K. Peterson Manager - Nuclear Licensing Enclosure cc:

w/Enclosure E. R. Duncan N. K. Ray NRC Resident Office Regional Administrator, Region HI Supervisor, Electric Operators, Michigan Public Service Commission

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A I)TE Energ Company

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3ports of independent registered iblic accounting firm nancial statements otes to consolidated financial statements

-year statistical review

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2004 annual report 1

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gg' Operating Revenues Electric Utility t

3,568 3,695 (3.4) %

Gas Utility 1

1,682 1,498 12.3 %

Non-utility

2,495

121917.7 Corporate & Other 16 12 33.3 %

Eliminations (647) i (283)

N/A 7,114 D 7,041 1.0 %

i Net Income Electric Utility Gas Utility Non-utility Corporate & Other

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-150 E-; `20 r I ~ 283 t:-

(1 0) jI 11I1iI i, f i

252 29 256 (57)

(40.5)

(31.0) 10.5 N/A

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Discontinued Operations Cumulative Effect of Accounting Changes 443 (12) -1 i ~

480 68 (27)

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(117.6) 1 $ -

431 I 521 (17.3).%

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iI Diluted Earnings Per Share Electric Utility Gas Utility Non-utility Corporate & Other Discontinued Operations Cumulative Effect of Accounting Changes Dividends Declared Per Share Dividend Yield Average Common Shares Outstanding (Millions)

Basic Diluted Book Value Per Share Market Price at Year End Total Market Capitalization Investments and Capital Expenditures Total Assets 0.87

0.11 1 1.63 (0.06) 1.50 0.17 1.52 (0.34)

(42.0)

(35.3) 7.2

(82.4) s -

2.55 -

2.85 (10.5) %

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0.40 (115.0) %

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2.49 3.09 (19.4) %

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173 173 i

$ 31.85 43.13 '

7,514 940

$ 21,297 2.06 5.2 %

1 (8.6) 168 168 31.36 39.40 6,643 785 20,753

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' 9.5 i 13.1

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, 2.6 total shareholder return N..

DTE Energy has consistently yielded strong performance for our shareholders.

Total shareholder return is the sum of share price appreciation and dividend yield.

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01 S&P Electric Index Source: CompuStat L6 i

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From top: DTE Energy Hydrogen Techonology Park, Southfield, Mich.; Dick Redmond (left) and Dale Walker, DTE Oil and Gas; Matt Korzelius (left) and Brian LoTempio, on-site energy facility, Tonawanda, N.Y I

4 2004 annual report

We faced enormous challenges in 2004. -Fortunately

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...by year end most were behind us. 'I'm pleased with the p'r'ogress we made.' But at the'sanme timei e'-I'm',

disappointed with our earnings performance...We.

4 expected 2004 to be'a low point in our business cycle '...' '

-and it i'is. The loss of reveniie due to Michigan's

-an d i f wa if ti-o s -r t i ;

Electric Choice program and the cost of implementatbon negatively impacted our bottom line by' niore'than.

$85 million or.50 cuntats as sare, year-over-year.

Our diluted earmngs per share were $2.49 in 2004 f--

..'.ctompar'ed to'$3.09 in 2003 'xIn 2005,'-we -should -f, '

<9',,^

rebound above 2003 levels We expect improvementm;,

across all of our.business segments.-

-=-;:<. Before :I 'd'e'scbe'our'plansrfor 2005 I'd like'to look > tig. il.>

:back at 2004.;.Addressing regulatory concerns-;-s s 1-

..-dominated our efforts. :In November, the Michigan -..<.a.;.

.';? ;Public'Service Commission (MPSC) issued a final order on our electric rate case It was the first rate increase in 10 years for our electric subsdiary

-Detroit Edison and among the most complex in

'.'- higi.. historyig We received a $74 increase in our base rates..;In addition, the MPSCr i'--:.decisioni improved the certainty of cost recovery on^-.

-- a number of fronts that will help'clear the way for Detroit' Ediondto earn a fair return.

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In terms of fixing Michigan's Electric Choice proga, the MPSC rate order was

--directio nally corret 'But theje is stil a.

lot of work to do on both the ruator and

.legislative froits The most p i

are unbundling rates-and eliminating subsidies for some rate se (see

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o reta).-

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rate ccase fied by our natural gas subsidiary MichConis was alSo the irstin a. deade.'-WNVexpect to receive a final ra er in the irst quaer of 2005.

Becaus e order will be issued late in l~t

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. the 2005 heatimg season, we will not benfit' ful y until 2006.'

Our second 2004 prioritywa cotiu

- coal into an energy source. Because we can only use a limited number of tax credits in anjgive nyeaij we accelerate cash generation by sellig interests in our portfolio. Byyea end, we had sold' m ore than 90 percent of our capacity, with plans to sell at least an aidditoiona 7 percnt 6 2004 annual report

65

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id achie; d

Iur as We expect to generate'approinmately $1.65 billion' leverage to'48 percent and achieved our cash-e c

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ween genetiongoal thru ghrigorous cos con rols.

,2005-2 Thscshpresents aunique oppor6'tunity'- '0' ---

as-,-Y-i-=i-'.sf o'fur efforts, w'eentered 2005 in -

to increase shareholder vaue'and strengthen'our a rnuc:'

than uchs ronger positionthan one year ago-.

,. balance shet Wehave asoli pla'eto nvbest o-ANe hWeidentif ied six business priorities as

..'this ca sh t

hat should help position'our company our success in 2005:

fr sucess in 2 5 for long-teirm griowth.(Reaid more about this n

.strategyin the sidebr 'of my letter.)

. c.e'a sustainabeElectric Choice pro 2.iflevelp a long"'-terregulatory strat gy'r

. Our third 2004 priorityh was to sustainthe

.'onmu or rothand vle creation.

company's growth momentum without stressing 4i4~ive srongfinancial anid balance:

our balance sheet.

e looked for only the very sheet-s trength.

,.'best investments and continued our non-utility, -

Make substantial progress toward growth for the eighth consecutiv er Our '- -.

vexcellen ce

_i,,accomplishments include -

Completing a deal with Daimleh lerto '

ing a inbleEctri Choie gr prvde on-site energy services at eight sites wl~ln ei 05 u ehv led in Mihgan, Indin an Ohio made progress.:.-Last month we complied with

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t;^t electricity serviersto attisu ml Aabaa.

resOgoli to'restuctr rtes estabhin

=. Growing our coke business. Currently we are '-.enegdliery and generationcagstt

-,',:Ex-,,KEpa'nding'our unc~onventional ga sproduction classes................

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tetwlsi the Bantsae nTxs

-copeitiv environment.;,.-

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..;,-Our fourth 2004 priority'was to maintain cash p

s al.ows timely'recovery of our ia dbale t

trength. We loeedour p

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2004 annual report 7

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.Our'second priority, is to de ii regulatory strategythat'not current'rate cases,: but antie investments in our'system.ui

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-eOur third priorityis toi ct creation This involves inve

'^.- non-utility opportumties, as grwn our g

reguated utiit

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.Weexect net income from a <

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also are develo pursuinfg the business wee

'..'Choice over the'past fewi ye

.. inew business opportunities

. We-do not,-however, intend:

='.'exene'f urb'alance'she,

':tto maintaining strong finani I ':balance sheet strength-. oi

, F ib :meet our targets for eari

.Scash flow, we must remain~

.costs. Our fifth priority,, prx 41 tL-'4i, operational excellence-

..'focus. -As we improve the'v

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-ofinancial performianc n x:-,.streamline processes, elimi reduce costs. '.We are developing a culture that

'-t@'t'- -, uses this approach on the job every day to boost.

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peformance and productivt. In 2004, we realized savings of approximately $105 million' value,,;,-

through variousOperatingiSystem i ovemets

- e'veraised the bar 'even hi for 2005 rony

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r masve,,tt redunansv fot-treplace our outdated and r-4 w-\\t-

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'eudn in~form'ation teholg sytm.'4-As we phase in our new computer system and

-.:-':'software, ve will improve our procedures for

'--4, finance',' supplychain' humansresourcesand citted operations..When this project is complete,'

e and 'i... we'expect steady state annual savings of - '

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annual sa-vings o

$"75 mfillion to $100 million.'

and Our final priority is to-build an engaged work iging

-force with the commitment and skills needed 4.-sl;t,°v S

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^'-todriveDTE Energys suiccess -This'is a broadW.

this target that starts with an intense'focus on safety ss, It iiiiolves training and developing our employees....u~f-to'ensurewe have the'right mix of skills and x.pertio r

tl theool ofuuleader also involves b in 3 j4.4 i

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2004 annual report

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- L,'.-succession plans.

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..I was yery pleased to announce list year l;.-the appointment of GerryAnderson as-

president of DTE Energy hGerry hase;

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,served for the past six years'as'a-group

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.'..president oversexeingour electricfpoWer'..---

,,=.-tplants and non-utility busies~siv-.hilih.. =,<-7^

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-i, ohaveav' trat6irintoan iriverh use-'Ž

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tX tes rspnibilities,'in his'new role he,a-,

i~l aso prov&ides executive leadership for :-^--.iB.'---

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-overall sttategic planning and other

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.- Gerrj and I arecoinmitted to deliverring S'f the type of value you have come tot expect from'DTE Energy On behalf off-'

all our 'employees thank you for your

'continu'ed support

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-Anthon alyJ Caraad Chie Eeu March120 Tvi r_ ry Ai -d1 a;t

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1Y Ij 2.K' Ger Anderson 66+.

Iur pl'rabfo rneivesting c asnh i=Weex^ectour non-utility bisines§ to genee $2 bilion in h f o

the

-A-1 wil provide a unique orbtunity to build our compans t~~f

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, 'value and s ape its future. We'intend to invst $350 million of this cash flow as

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equity in Detroit Edison to help fund ouir cean air investments' This leaves,

$1.65 billion to redeploy in other wiays.

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Ourprimar objeictives in redeploying this cas are to Shape our balance sheet to meet both our near-term and long term cr-e'.credit objectives..

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' Repiace and 'exceed the value' of s cash flow'currently inherent in our stock price.

We expect to achieve these objectives by:. '

-. '..Reducing parent company debt' approximately one-third by 2008.

. ; Investing in new businesses that meet our strict risk-return and lue'-dreation criteria. We believe we can'successfully deploy ',,

'- A i-$600hillhion to $900 million of capital into non-utility businesses -

f6m2005-2008 at attractive returns. -

Repufrchasing shares to help build vaiue6 tothe degree that adequate investment opportunities -are not available."

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-cash wisely with disciplnme and a keen focus on building value. We're confident

-Vwe will dothat and in'the process -lay the foundation-for a strong' future.,

.Above: Coke battery operation, Gary, d.

2004 annual report 9

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N ega yf' excel cen the impo eof se our customer wel..

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and cont

'pin

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and e cd the eetatons a

'At the same time we gro ou c be'

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wemsshrik csts. The DTE EnergyOperatig 1-:L:.

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se is a powerful tool wersn t ojs that.

I's a sta r t t b

.~~W were te-...:l,.,st

,d in 200 whe 4focsdo reducing waste, imj.................processes..

hampered ou growth.

lButwe remained focused, Littlments CA nce ii on reaning the health f our duteiliti prges In 205 Aardmd ccrigt BbBune neetrca h

Det ro eds fixes t ransfres a ithe Warren Servi Cente DtotE onand Michion wlcotueo electric al shop..Because o h hne ev their financial ist d pLositi6n' r,

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er gh s,

Ivthemelves forfutregrowtlong em;'we Icontrolmyowndestiny" s expect to generate 70 percent of DTE Enerr 1

earnings froim regu ted o'petor.'.-Fixing these tnoe si m

~,,,,,month wh'e'n the'-y arrived at the 51'acere service omketishape e muste Roning that was 'unaccep` ablea a, 4

4

o Mgr~ichelyuse t he uines we'vem lostl temo uinad aae en Fempaoyeesused Operating tem tools to study P

seek new busi ess PI

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eydiscovered each transformer' K*

Continue to reduce ctst throurv five miles withinthe facility during jf operatingefficienciesrepair and, once ixe oo e proactiv in ma days g d regulatory process 10 2004 annual report 11

71771U 2004 annual report 11

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--Armed with this knwegteta reated stan dard orkins i

bis repairs me u n_

thet '

company an estimated $500,000 hi the

~--~.rarsfmearea'alone. ~Besto-fall,-rpi'.-,.

inn-,are now comnpleted in just eight hours.

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Co!mbined 'ith other Operating System powe~~rp..

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inta e'te1 bierviti

-e en ter tftf1 svnsexceeding $1.3 milion in20 he ulimategoal f theDTE EneryOeang Sysem s t raseperformance to a new lvl adoter aculture o change as awayto improveand learn-Les Cilck',. elcrcalsh leaider sayis iy`, sTe umio s w thatthe Operating Sse a~a business opportunity -aind took an you kow what? Most eo p le are happier niow because they ko ht

_expected; they. aren't as stressed erut.

Carryin off a coimnp'lcatid refuelin outage~~

sely was a te iaeffort at our Fermi 2 nuclear power plantThanks to the perat mg System,71 tEhe plant-completed its last outage in 27 days, t

beating its_ prei is recor by an in3pressive I r six days -Clearly, using tools'of the Operating,~

Systemn he'lpedA us-complete' thejoutage safely,i.,.

12cost effectively and inrrecorrd ti me aBl v

president of nuclear generation.

[1n2~00te Nm~waawaedthe'state'shigh6§t:

saey bognition, the Michigan Volunty 12 2004 annual report

q Employees at the Broadway Station,-a MichCon

-facility used the Operating System to substantially -f

.increase their productnty. With the lowest field,-,

service productivity of all our Detroit area service t' centers, the Broadway Station assessed, analyzed r

and improved the situation byimplementing c

tools of the Operating System. 'Going from worst to first m performance, todaythe Broadway Station is numnber one in productivityi. -

ill Cost savings and increased productivity arejust two of the benefits of the Operating System.

It's also'helping us

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~ -. ",.:Redu'ce injuries. ;-w'--W..';-fE

Reduc'e'absenteeiSM

Reduce power plant emissions Speed up the hiring process.

e Improve customer restoration times.'

Reduce customer complaints.

Were proud of our successesi'but recognize there

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_ -are still many opportunities to improve. In 2005,,

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drive the'Operating System evenideeper.L'.`,;-

into our organization with a goal i identify

,r;,savings of at least $125 million. :--< i.t.r-3.

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)TE Energy Operating System is

ernally, we're focused'externally on he regulatory environment for our urfgoal is to establish a multi-year trategy that addresses currenit and ticipates future~ne'edsb'ased..',;

nging marketplace. e.,-.,,.;

tterm, we'll continue to build stable

'in the regulatory arena, and develop lmg and support for key energy policy,-.-

re' th'e-y reach the crisis stage' In thel,,,'.,

-we'll tackle several issues that will -..

y impact the performance of our rm of Elecrc Choice'!,.

,,/o income energy assistance indhng and restructuring electric rates.'.>,

ironmental controls and cost recovery.

gfewyeals rising health care'osts,-

ure costs, bad debt expense and 6fetr

_--e

sfro'm Electric Choice outstripped-.

yings at ouriutilities. But witha.~.-..

tion of our electric and natural gas. L.' -

gol is'to'moveb roit ichCon to their authorized',0

,raeof retur'n.-.We view.2005 as'a'

'A aullding for our utilities, zwitl* a return - ;

narfpeiformance leivels in 2006-. <2.'.Y ZI i'..'M..(.' >'-.,?. ;

I'11 2004 annual report 13

jI-

.investing fr gro" tsjutone exampl of ouor growth strategy for non-utility businesses. Our investments follow:-

two broad approaches:

'th Our strategy is to grow in areas closely linked:

to our utlteboth in the type of b usiness and ini the skidls they reqluire.

Our entry into thefBarnett' shale, for example builds on our many years of experiencedwith Antrini shale production. DTE Energy is the second largest operator of Antrimi gas wells in Michigan, m-ainaging approximnately, 1400 Antrim shaewellsthat produce 22 Bcfayearn:,'.,

Our strong technical and operating expertise-allows us t~o keep expenses down and remain,:

one of the lowest cost operators in the state.

When we evauate potentialinvestm-entswe look A;-

for a fit in'on~e ofthree areas:

Power and industrial projects, such as

o-n-site energy and steel-related projecs power generation and waste coal recovery;

U cnventionlga rduction, such as shale and landfill gas production;

Fuel transportation and marketing, such as coal services, gas pipelines and storage, and;!

e6nergy mnarketing a dtaig We have an i mpressiv'e track record linthese areas, particularly with on-site energy services.

We operate 19 major sites for heavy energy users i in-the automotive, ste-el, pulp and paper, and commercial and institutional-sectors& This includes nine sites added to our portfolio in 2004.1

Niche businesses'with limited competition and strong returns,,such as arettsae svnfuel production, industrial coke and waste coalrecovery--

Lower risk businesses where we can add value, such as on-sit energy poet that leverageour operto sad maniagement experience.

We focus on valu.

No sie and scope. B realnig true to, this ph-ilosophy, our non-utilit i businfes~ses9 grew substantiallyfoth eigt consecutive year.

And we exetnticm from these~b~usinesses toincr~ease app.roximately-30 percent in 2005 I

14 2004 annual report Ii

'terriory I3/4 I

2004 annual report 15

One' 'of our newest transactions is a 20-ye contrac'e1t with DalmlerChuysler to provide utility service at eight sites 'in Michigan;,-

Ohi1do and Indiana. Also new hi 2004 was T

our entry into the pulp and paper sector,

,withian agreement to provide7 steam and:

Ielectricity for a tissue mill in.Mobile, Ala.

In addition, we're! now con-struLicting a, '

faclity to supply multiple paper mlIs with ulverized solid fuel.':

Our steel-related businesses are also growing. We're the second largestli:.

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g:.

m_-rchant producer of blast furnace coke,

_a coal derivative used to produce steel.

We own22 percent of independent blast fuirnace coke production in North Arericai with the1potential to increase our share substantiallyin the next few years.1 Builin on o Ur expertise around coal, we began operating our first waste coal reco'very plant "in 2004. Using proprietary,:E technology we're turning coal slurry fron waste ponds into a quality of coal alm st --

s g~oodas that produced from the original',-

16 2004 annual report

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mine. We're refining this process, and believe there's great potential in this untapped market.

L:veraging our knowledge and experience in power plant operations, in 2004 we began providing services to financial institutions that.

control distressed power generation assets.

We currently manage and operate two plants,

'one in Connecticut and one in California, that'-

' 'produce 1,800 MW of electricity. 'We have no

--'equity in these projects, but earn a fee for the

- servce we provide.

Our'strong reputation in delivering on-site services, combined with our expertise in coal, is leading to other opportunities in power generation. 'For example, we're developing -

a 200-MW coal-fired power plant for an-

international mining company with operations in the western U.S. We will look for similar ventures with other companies.

Our existing gas pipelines and storage business' also offers growth potential. -We own'40 percent

-of the Vector pipeline, a 348-mile interstate pipeline supplying natural gas from Chicago to,:

Dawn, Ontario. The pipeline, which is operating at fill capacity, runs through the heart of MichCon's service territory and gas storage e fields. Because demand in the region is very pansion of Vector is likely,'as is--

of our Michigan storage fields.-

percent of the proposed line that will run from western v York City. We-view Millennium hide to move gas out of storage into markets in New York City the Northeast.

-7, L' I

I _I ears present incredible ortunities across our portfolio isinesses, thanks to the excess from our synfuel businesses.:-

this in the Chairman's letter.)

plan to continue following our management strategy. We do row at the expense of our balance Ian to seek quality investments it exceed our cost of capital.-

0 focus on opportunities closely ore businesses.

ght years, we have built an ecord of successful investments.

Led to sustain it.

2004 annual report 17

board of directors

., I _1..

Committee membership: A-Audit, C-Corporate Governance, E-Executive (disbanded in November 2004), F-Finance, N-Nuclear Review, O-Organization and Compensation, P-Public Responsibiliy, S-Special Committee on Compensation (disbanded in April 2004) 18 2004 annual report

executive committee*

Earl~~J~

55 s chirmn, chieexctvof aspesdn an o n htsm erwselected a dire' elcedt hscrren poiion in,~Beor jonngWE Eu

~dw rkedsic 1985 Gear M nesn 5~peietof DTE Energ -in "sein four peietoEnryRsucsrevioi exctv ie presidentEof erTE. Anderson joined th 193 rm oi n se y &Wterhe was a consultant in en(

DvdE Mar, iexcutiv viepeident adche

.(F) ejie T Eeg n19 svc president arid con e~cesenj si~anCOi 01. In 2004 e a currnt osiior~lna~1i iti~l~ eador served as si

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lfiiiarci& an ccutnpoiosatCrysler Corp. for14 y ea

- a~idit~ir i-Coopers nd

'Susan MBal56iviepeintand o

..corporat.9 secpretary She" jonehecopnya an attorney, in -1982eaewanmJcoprt

~-secretaiy in 1989'6 and as lctdvieprsdetHe in 99.'She cameto'DTI.Efnergyahferfouyar oit wihIh lgal staff of Southern CaliforniaEio ad two ears w ith nsumersi Powier Roer Buker, 55 sgoppeieto IJTE En ergy irbuoqHe foined the company:

Bene 1974 and was named to his current ps n19

~~-ihas held numerous positins throughout fe, orgniztin ichdii'powrer plan~t egineeig 9r aic~

a7~~

14y Steplhen E.Ein 60 isgou rsietof 5

DTE Energy Gas. Hjondte compn in 201from MCN Energy,Werekhe'sierve as

~Jie ispresident an c-corpo president~dcife c fe'b c eerif n.,joinedc and Michi

For more information on other DTE Energy officers, go to dteenergy~corrtrinvestors.

2004 annual report 19

one strategy, many Options Excuie Vice President and Chief Financial Officer Dave Meador 41

'I believe we have tumned the cormer. With our electric and natural.I

'gas rate cases behind us,we expect the financial health of our two utilities to improve considerably in 2005. We anticipate cash flows will improve dramatically, providing significant financial flexibility.

Arid we plan-to continue to grow our non-utility businesses.-

You've already read about our opportunity to reinvest approxinately

$1.65 billion in cash, expected prirn from synfiuel over the next

-four years. Included in the total is an additional $400 million from growth of our other non-utility businesses.

-As we evaluate our options for redeploying this cash, we will seek investments that create value and are consistent with our strategy..

.-'At the same time, we will remain disciplined. We plan to build on our company's unique strengths and pursue closely related businesslines.-

Our plans include investing where the competition is manageable, while focusing on cash flow first, scale second. 'The obje is to test business proposals with limited capital before malinig sigificant investments. And if we can't find opportunities that meet our stringent criteria, we intend to return the cash to our shareholders through stock repurchases.

.Likewise, our financial objectives have remained constant:

-Focus onvalue creation (achieve returns that exceed our cost of capital).'

Maintain a strong balan'ce sheet and solid investment grade rating.

-SGenerate future earnings growth.:

' Maintain our dividend at $2.06 per share while our utilities

.. improve their health.

Continue to communicate openlyand transparently about our performance.

Remaining true to these objectives has helped us yield strong-.' I

-performance for our shareholders over the last five and 10 years. The exception was 2004, when uncertainty surrounding 10

.er.

Th; 004

.d W

Detroit Edison's electric rate case slowed our momentum.

. Despite this challenge, we maintained the growth of our

.; ~ ~

~

dr

,t-.

'non-utility businesses as we focused on rebuilding our utilities.

I am deeply committed to achieving our financial objectives.:

-I do not intend to let you down.'

-=

David E Meador Execufive Vice President and Chief Financial Oflicer -

We 'are proud of our track record of delivering shareholder value.

The long-term success of our company can be attributed to a solid'

-strategy fromwhichwe do notwaver.-

20 2004 annual report

management's discussion and analysis of financial condition and results of operations OVERVIEW DTE Energy is a diversified energy company with approximately

$7 billion in revenues in 2004 and approximately $21 billion in assets at December 31, 2004. We are the parent company of Detroit Edison and MichCon, regulated electric and gas utilities engaged primarily in the business of providing electricity and natural gas sales and distribution services throughout 7

southeastern Michigan. Additionally, we have numerous non-utility subsidiaries involved in energy-related businesses predominantly in the Midwest and eastern U.S.

A significant portion of our earnings is derived from our utility operations, synthetic fuel business, and energy marketing and trading operations. Earnings in 2004 were $431 million, or

$2.49 per diluted share, down from 2003 earnings of $521 million, or $3.09 per diluted share. As discussed in the "RESULTS OF OPERATIONS" section that follows, the comparability of earnings was impacted by discontinued businesses and the adoption of new accounting rules. Excluding discontinued operations and the cumulative effect of accounting changes, earnings from continuing operations in 2004 were $443 million, or $2.55 per diluted share, compared to earnings of $480 million, or $2.85 per diluted share for the same 2003 period. Income reflects reduced contributions from our utility operations, partially offset by increased contribu-tions from our non-utility businesses and Corporate & Other.

Significant items that influenced our 2004 financial performance and/or may affect future results are:

Electric Customer Choice penetration;

Electric and gas rate orders;

Higher operating costs;

Weather;

Synfuel-related earnings and the risk of higher oil prices; and

Growth of non-utility businesses.

Electric Customer Choice Program - Since 2002, Michigan residents and businesses have had the option of participating in the electric Customer Choice program. This program is designed to give all customers added choices and the opportunity to benefit from lower power costs resulting from competition.

However, Detroit Edison's rates are regulated by the Michigan Public Service Commission (MPSC), while alternative suppliers can charge market-based rates. This regulation has hindered Detroit Edison's ability to retain customers. In addition, the MPSC has maintained regulated rates for certain groups of customers that exceed the cost of service to those customers.

This has resulted in high levels of participation in the electric Customer Choice program by those customers that have the highest rates relative to their cost of service, primarily commercial and industrial businesses. As a result, our margins continue to be affected. To address this issue, we filed a revenue neutral rate restructuring proposal in February 2005 designed to adjust rates for each customer class to be reflective of the full costs incurred to service such customers. Under the proposal, Detroit Edison's commercial and industrial rates would be lowered in 2006, but residential rates would increase over a five-year period beginning in 2007. The number and mix of customers participating in the electric Customer Choice program could be impacted under the rate restructuring.

Lost margins and electricity volumes a

associated with electric Customer Choice were approximately $237 million and 9,245 gigawatthours (gWh) in 2004. This compares with lost electric Customer Choice margins and volumes of approximately $120 million and 6,193 gWh in 2003. The financial impact of electric Customer Choice was affected by the issuance of electric interim and final rate orders that increased base rates, authorized transition charges and reaffirmed the resumption of the Power Supply Cost Recovery (PSCR) mechanism, as subsequently discussed. Partially offsetting the impact of lost margins on income, we recorded regulatory assets representing stranded costs that we believe are recoverable under existing Michigan legislation and MPSC orders.

There are a number of variables and estimates that impact the level of recoverable stranded costs, including weather, sales mix and transition charges. As a result, our estimate of stranded costs could increase or decrease. As subsequently discussed, the MPSC authorized the recovery of $44 million in stranded costs for the period of January 2002 through February 2004.

Detroit Edison rate orders, along with the rate restructuring proposal, address certain issues with the electric Customer Choice program. However, current regulation continues to hinder our ability to retain certain customers. Accordingly, we will continue working with the MPSC and Michigan legislature to address other issues associated with the electric Customer Choice program.

Electric Rate Orders - In 2000, Public Act (PA) 141 froze electric rates for all residential, commercial and industrial customers through 2003. The legislation also prevented rate increases (or capped rates) for small commercial and industrial customers through 2004 and for residential customers through 2005. The rate freeze and caps apply to base rates as well as rates designed to recover fuel and purchased power costs which has traditionally been a cost pass-through under the Power Supply Cost Recovery (PSCR) mechanism.

In 2004, the MPSC issued interim and final rate orders that authorized electric rate increases totaling $374 million, and eliminated transition credits and implemented transition 2004 annual report 21

charges for electric Customer Choice customers. The increases were applicable to all customers not subject to a rate cap. The interim order affirmed the resumption of the PSCR mechanism for both capped and uncapped customers, which reduced PSCR revenues by $115 million in 2004. However, the order allowed Detroit Edison to increase base rates for customers still subject to a cap in an equal and offsetting amount to the change in the PSCR factor to maintain the total capped rate levels in effect for these customers.

The MPSC also authorized the recovery of approximately $385 million in regulatory assets, including stranded costs.

As a result of rate caps, regulatory asset adjustments and other factors, the rate orders decreased 2004 earnings by $15 million.

The impact of the rate orders is expected to increase earnings in 2005 and 2006 as rate caps expire.

Effect of Interim and Final Rate Orders (in Millions) 2004 Base Rate Increase and Transition Charges 154 PSCR Reduction (11 5

Regulatory Assets Stranded costs adjustment (33)'

Regulatory asset deferrals - cessation (1)

(29)

Pre-Tax Income (Decrease)

(23)1 Net Income (Decrease)

(15)

(1)We ceased recording regulatory assets for costs that are reflected in rates pursuant to the MPSCs 2004 rate orders.

See Note 4 for a further discussion of the MPSC's interim and final rate orders.

Gas Interim Rate Order - In September 2003, MichCon filed an application with the MPSC for an increase in service and distribution charges (base rates) for its gas sales and trans-portation customers. The filing requested an overall increase in base rates of $194 million annually (approximately 7% increase, inclusive of gas costs), beginning January 1, 2005. In September 2004, MichCon received an interim order in this rate case authorizing an increase in base rates of $35 million annually, effective September 22, 2004. The interim rate order increased earnings by approximately $6 million in 2004. MichCon expects a final order from the MPSC in the first quarter of 2005.

Operating Costs - During 2004, we experienced increases in operation and maintenance costs, primarily within our electric and gas utilities. The increases were driven by higher costs associated with pension and postretirement benefits and uncollectible accounts receivable.

Pension and postretirement benefits expense totaled $212 million in 2004, compared to $172 million in 2003. The increase is due to financial market performance, lower discount rates and increased health care trend rates. We have made modifications to the pension and postretirement benefit plans to mitigate the earnings impact of higher costs. Additionally, the recoverability of pension and health care benefits costs were part of our electric and gas rate filings. The MPSC approved a pension tracking mechanism in Detroit Edison's final rate order that provides for the recovery or refunding of pension costs above or below the amount reflected in base rates. The MPSC also required Detroit Edison to propose a similar tracking mechanism for retiree health care costs. Detroit Edison filed a request with the MPSC in February 2005 seeking authority to implement a tracking mechanism for retiree health care costs.

Both utilities continue to experience high levels of past due receiv-ables, especially within our Energy Gas operations. The increase is attributable to economic conditions, high natural gas prices and the lack of adequate levels of assistance for low-income customers.

As a result of these factors, our allowance for doubtful accounts expense for the two utilities increased to $105 million in 2004 compared to $76 million for the corresponding 2003 period. We are taking aggressive actions to reduce the level of past due receivables, including customer disconnections, contracting with collection agencies and working with the State of Michigan and others to increase the share of low-income funding allocated to our customers.

In MichCon's current gas rate filing, we addressed numerous operating cost issues, including uncollectible accounts receivable expense. The MPSC Staff supports a provision proposed by MichCon that would allow MichCon to recover or refund 90% of uncollectible accounts receivable expense above or below the amount that is reflected in base rates. We support the MPSC Staff's recommenda-tion and believe the provision would significantly reduce our risk of high uncollectible gas accounts receivable.

To partially address this issue of rising costs, we continue to employ the DTE Energy Operating System, which is the application of tools and practices to obtain operating efficiencies and enhance operat-ing performance. We are targeting over $100 million in savings during 2005 through the application of Operating System principles.

Weather - Earnings in our electric and gas utilities are seasonal and sensitive to weather. Electric utility earnings are dependent on hot summer weather, while the gas utility's results are driven by cold winter weather. We experienced both milder summer and winter weather during 2004, which negatively impacted sales demand. The lower demand reduced current year earnings by

$27 million compared to 2003.

Additionally, we occasionally experience various types of storms that damage our electric distribution infrastructure resulting in power outages. The impact of storms on our current year earnings was significantly lower than in 2003, which was affected by several catastrophic wind and ice storms, as well as by the August 2003 blackout. Restoration and other costs associated with storm-related power outages lowered 2004 pretax earnings by $48 million compared to $72 million in 2003.

Synthetic Fuel Operations - We operate nine synthetic fuel production plants at eight locations. Since 2002, we have sold majority interests in eight of the nine plants, representing approximately 92% of our total production capacity. Synfuel facilities chemically change coal, including waste and marginal coal, into a synthetic fuel as determined under applicable Internal Revenue Service (IRS) rules. Section 29 of the Internal Revenue Code provides tax credits for the production and sale of solid synthetic fuel produced from coal. Synfuel-related tax credits expire in December 2007.

Operating expenses associated with synfuel projects exceed operating revenues and therefore generate operating losses, which have been more than offset by the resulting Section 29 tax credits. In order to recognize Section 29 tax credits, a taxpayer must have sufficient taxable income in the year the tax credit is generated. Once earned, the tax credits are utilized subject to 22 2004 annual report 11

certain limitations but can be carried fonvard indefinitely.

We have not had sufficient taxable income to fully utilize tax credits earned in prior periods. As of December 2004, we had

$483 million in tax credit carry-forwards. In order to optimize income and cash flow from our synfuel operations, we have sold majority interests in eight of our nine facilities and intend to sell a majority interest in the remaining plant during 2005, representing 99% of our production capacity. When we sell an interest in a synfuel project, we recognize the gain from such sale as the facility produces and sells synfuel and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectability is reasonably assured. Gain recognition is dependent' on the synfuel production qualifying for Section 29 tax credits and the value of such credits as subsequently discussed. In substance,,,

we are receiving synfuel gains and reduced operating losses in exchange for tax credits associated with the projects sold. Sales of interests in synfuel projects allow us to accelerate cash flow while maintaining a stable income base.

The value of a Section 29 tax credit can vary each year and is adjusted annually by an inflation factor as published by the IRS in' April of the following year. Additionally, the value of the tax'credit in a given year is reduced if the "Reference Price" of oil within the year exceeds a threshold price and is eliminated entirely if the Reference Price exceeds a phase-out price. The Reference Price of a barrel of oil is an estimate'of the annual average wellhead price per barrel for domestic crude oil, which in recent years'has been $3 -$4 lower than the New York Mercantile Exchange (NYMEX) price for light, sweet crude oil. The actual or estimated Reference Price and beginning and ending phase-out prices per barrel of oil for 2003, 2004 and 2005 are as follows:

Reference Beginning Ending Price Phase-Out Price Phase-Out Price 2003 (actual)

$27.56

$50.14

$62.94 2004 (estimated)

$37.61

$51.34

$64.45 2005(estimated) NotAvailable

$52.37

$65.74 Assuming no synfuel tax credit phase out in future years, we expect cash flow from our synfuel business to total approximately

$1.6 billion between 2005 and 2008. The source of synfuel cash flow includes cash from operations, asset sales, and the utilization of Section 29 tax credits carried forward from synfuel production prior to 2004.

Non-utility Growth - During 2004, we continued to experience growth in our non-utility businesses with income reaching

$283 million compared to $256 million in 2003. The improvement primarily reflects increased contributions in our Energy Marketing

& Trading segment, primarily due to a one-time contract gain.

Additionally, non-utility growth in 2004 is attributable to increased earnings from our synfuels, coke batteries and on-site energy projects. Also affecting the year over year comparison are asset gains, losses and impairments during 2004 and 2003 as subsequently discussed.

Outlook - We made significant progress during the past year on our 2004 corporate priorities, which included:

Successful rate case outcomes;

Addressing structural issues with the electric Customer Choice program;

Continuing sell-down of synfuel portfolio;

Continuing non-utility growth momentum; and

Maintaining cash and balance sheet strength.

Our long-term strategy has not changed and in 2005 we will focus on maintaining a strong utility base, pursuing a unique growth strategy focused on value creation in targeted markets, maintaining a strong balance sheet and paying an attractive dividend. The impact of the rate orders is expected to increase utility earnings in 2005 and 2006 as rate caps expire.

Our financial performance will be dependent on successfully redeploying an expected $1.65 billion of cash flow through 2008, primarily associated with proceeds from the sale of interests in synfuel facilities. Our objective for cash redeployment is to strengthen the balance sheet and coverage ratios, as well as replace the value of synfuels that is currently inherent in our share price. We will first use our cash to reduce parent company debt. Secondly, we will continue to pursue growth investments that meet our strict risk-return and value creation criteria.

Lastly, share repurchases will be used to build share value if adequate investment opportunities are not available.

RESULTS OF OPERATIONS We had earnings of $431 million in 2004, or $2.49 per diluted share, compared to earnings of $521 million, or $3.09 per diluted share in 2003 and earnings of $632 million, or $3.83 per diluted share in 2002.-As subsequently discussed, the comparability of earnings was impacted by our two discontinued businesses, International Transmission Company and Southern Missouri Gas Company, and the adoption of two new accounting rules in 2003.

Excluding discontinued operations and the cumulative effect of accounting changes, our earnings from continuing operations in 2004 were $443 million, or $2.55 per diluted share, compared to earnings of $480 million, or $2.85 per diluted share in 2003 and earnings of $586 million, or $3.55 per diluted share in 2002. The following sections provide a detailed discussion of our segments, operating performance and future outlook.

2004 annual report 23 Numerous recent events have significantly increased domestic crude oil prices, including terrorism, storm-related supply disrup-tions and strong worldwide demand. As of February 1, 2005, the NYMEX closing price of a barrel of oil to be delivered in March 2005 was $47.12, which is comparable to a $43.47 Reference Price (assuming that such price was to continue for an entire year).

For 2005 and later years, if the Reference Price falls within or exceeds the phase-out range, the availability of tax credits in that year would be reduced or eliminated, respectively.

As previously discussed, until the gain recognition criteria is met, gains from selling interests in synfuel facilities will be deferred.

It is possible that gains will be deferred in the first, second and/or third quarters of each year until there is persuasive evidence that no tax credit phase out will occur for the applicable calendar year.

This could result in shifting earnings from earlier quarters to later quarters of a calendar year.

As discussed in Notes 12 and 13, we have entered into derivative and other contracts to economically hedge approximately 65% of our 2005 synfuel cash flow exposure related to the risk of an increase in oil prices. We are continuing to evaluate the current volatility in oil prices and alternatives available to mitigate our unhedged exposure to oil prices as part of our synfuel-related risk management strategy.

Segment Performance & Outlook - Through 2004, we operated our businesses through three strategic business units (Energy Resources, Energy Distribution and Energy Gas). Each business unit had utility and non-utility operations. The balance of our business consisted of Corporate & Other. This resulted in the following reportable segments. In 2005, we expect to realign our business units as discussed in Note 1.

(in Millions) 2004 2003 2002 Operating Revenues S 2,210 3-?$

2,448 $ 2,711 Fuel and Purchased Power 868 i X 920 1,048 Gross Margin 1,342 1,528 1,663 Operation and Maintenance 672 628 626 Depreciation and Amortization 27 224 331 TaxesOtherThan Income

-147 157 156 Operating Income 251 519 550 Other (Income) and Deductions

-166' 149 189 Income Tax Provision 23 135 120 Net Income 62 235 $

241 Operating Income as a

=

Percent of Operating Revenues 11 %

21 %

20 %

(in Millions, exceptper share data) 2004 2003 2002 Net Income (Loss)

Energy Resources Utility-Power Generation S

62, $

235 $

241 Non-utility Energy Services vi 188 j 199 182 Energy Marketing & Trading 92; 45 25 Other (2) 7 Total Non-utility 281 242 214 343 477 455 Energy Distribution Utility - Power Distribution 88 17 111 Non-utility (19)

(15)

(16)

-69 2

95 Energy Gas Utility - Gas Distribution 201 29 66 Non-utility

,',21 i

29 26

411, 58 92 Corporate & Other (10)

(57)

(56)

Income from Continuing Operations Utility

170, 281 418 Non-utility 283 256 224 Corporate & Other M

(10)

57)

(56) 443-480 586 Discontinued Operations (12) 68 46 Cumulative Effect of Accounting Changes (27)

Net Income 431 $

521 $

632 Diluted Earnings Per Share Utility

$ -98i 1.67 $

2.53 Non-utility 1.63 1.52 1.36 Corporate & Other

(.06)

(.34)

Income from Continuing Operations 2.55' 2.85 3.55 Discontinued Operations

(.06)

.40

.28 Cumulative Effect of Accounting Changes

(.16)

Net Income 2.49. S 3.09 $

3.83 Gross margin declined $186 million during 2004 and $135 million in 2003. The declines were due primarily to lost margins from retail customers choosing to purchase power from alternative suppliers under the electric Customer Choice program as well as reduced cooling demand resulting from mild summer weather. As a result of electric Customer Choice penetration, Detroit Edison lost 18%

of retail sales in 2004, compared to 12% of such sales during 2003.

The loss of retail sales under the electric Customer Choice program also resulted in lower purchase power requirements, as well as excess power capacity that was sold in the wholesale market.

Under the 2004 interim and final rate orders previously discussed, revenues from selling excess power reduce the level of recoverable fuel and purchased power costs and therefore do not impact margins associated with uncapped customers. The rate orders also lowered PSCR revenues, which were partially offset by increased base rate and transition charge revenues.

Weather in 2004 was 3% milder than 2003, resulting in lost margins of $25 million. Weather in 2003 was also milder than the prior year, resulting in lost margins of $114 million. The decline in margins and revenues in 2004 was also due to the allocation of a smaller portion of Detroit Edison's billings to Power Generation.

Sales Lost to Electric Choice in gWh

'.245i 1

I267J I

ENERGY RESOURCES Utility - Power Generation The power generation plants of Detroit Edison comprise our regulated power generation business. Detroit Edison's numerous fossil plants, its hydroelectric pumped storage plant and its nuclear plant generate electricity. The generated electricity, supplemented with purchased power, is sold principally throughout Michigan and the Midwest to residential, commercial, industrial and wholesale customers.

Factors impacting income: Power Generation earnings decreased

$173 million in 2004 and $6 million in 2003, compared to the prior year As subsequently discussed, these results primarily reflect reduced gross margins and increased operation and maintenance expenses.

24 2004 annual report 2002 2003 2004 Operating revenues and fuel and purchased power costs decreased in 2004 and 2003 reflecting a $1.27 per megawatt hour (MWh)

(8%) decline in fuel and purchased power costs during 2004 and a $.64 per MWh (4%) decline during 2003. Fuel and purchased power costs are a pass-through with the reinstatement of the PSCR in 2004, and therefore do not affect margins or earnings associated with uncapped customers. The decrease in fuel and purchased power costs is attributable to lower priced purchases and the use of a more favorable power supply mix driven by higher generation output. The favorable mix is due to lower purchases, driven by lost sales under the electric Customer Choice program.

The comparison was also affected by higher costs associated with 11

substitute power purchased to meet customer demand during the August 2003 blackout. We were required to purchase additional power during the 36-day period it took for our generation fleet to return to pre-blackout capacity.

fin Thousands ofMIAM) 2004 2003 2002 Electric Sales and Use Retail E4 9,

379

-43,672 48,346 Wholesale and Other 8.569 5,600 6,128 F48,948 49,272 54,474 Internal Use and Line Loss 3,574 3,248 3,651

=52.522 52,520 58,125 (in Thousands ofMMW,)

Power Generated and Purchased Power Plant Generation Fossil 39,432 ;75 % 38,052 72% 39,017 67%

Nuclear (Fermi 2)

>'i:8,440 116 8,114 16 9,301 16

.47,872 91 46,166 88 48,318 83 Purchased Power 4,550 9

6,354 12 9,807 17 SystemOutput 105Z52 10% 52,520 100%

58,125 100%

Average Unit Cost ($/MWh)

Generation (1) 12.98

$ 12.89

$ 12.53 Purchased Power (2) i S;S 37.06;

$ 41.73

$ 39.16 Overall Average UnitCost r--'-'.S:15.1i

$ 16.38

$ 17.02 I1) Represents fuel costs associated with power plants.

(2) Includes amounts associated with hedging activities.

Operation and maintenance expense increased $44 million in 2004 and $2 million in 2003. The 2004 increase reflects costs associated with maintaining our generation fleet, including costs of scheduled and forced plant outages. Additionally, the increase in 2004 is due to incremental costs associated with the implemen-tation of our DTE2 project, a Company-wide initiative to improve existing processes and to implement new core information systems, including finance, human resources, supply chain and work management. Operation and maintenance expense in both years includes higher employee pension and health care benefit costs due to financial market performance, discount rates and health care trend rates. Expenses in 2003 were also affected by

$5 million in costs associated with the August 2003 blackout.

Depreciation and amortization expense increased $48 million in 2004 and decreased $107 million in 2003. The variations reflect the income effect of recording regulatory assets, which lowered depreciation and amortization expenses. The regulatory asset deferrals totaled $107 million in 2004 and $153 million in 2003, representing net stranded costs and other costs we believe are recoverable under PA 141.

Other income and deductions expense increased $17 million in 2004 and decreased $40 million in 2003. The 2004 increase is primarily due to lower income associated with recording a return on regulatory assets, as well as costs associated with addressing the structural issues of PA 141. The 2003 decrease is attributable to lower interest expenses and increased interest income.

Interest expense reflects lower borrowing levels and rates, and interest income includes the accrual of carrying charges on environmental-related regulatory assets.

Outlook - Future operating results are expected to vary as a result of external factors such as regulatory proceedings, new legislation, changes in market prices of power, coal and gas, plant performance, changes in economic conditions, weather and the levels of customer participation in the electric Customer Choice program.

As previously discussed, we expect cash flows and operating performance will continue to be at risk due to the electric Customer Choice program until the issues associated with this program are addressed. We will accrue as regulatory assets our unrecovered generation-related fixed costs (stranded costs) due to electric Customer Choice that we believe are recoverable under Michigan legislation and MPSC orders. We have addressed certain issues of the electric Customer Choice program in our February 2005 rate restructuring proposal. We cannot predict the outcome of these matters.

In conjunction with the sale of the transmission assets of ITC in February 2003, the Federal Energy Regulatory Commission (FERC) froze ITC's transmission rates through December 2004. It is expected that annual rate adjustments pursuant to a formulistic pricing mechanism beginning in January 2005 will result in an estimated increase in Detroit Edison's transniission expense of

$50 million annually. Additionally, in a proceeding before the FERC, several Midwest utilities seek to recover transmission revenues lost as a result of a FERC order modifying the pricing of transmission service in the Midwest. Detroit Edison estimates that its potential obligation as a result of this proceeding could be

$2.2 million per month from December 2004 through March 2005 and $1 million per month from April 2005 through March 2006.

Detroit Edison is expected to incur an additional $15 million in 2005 for charges related to the implementation of Midwest Independent Transmission System Operator's open market. As pre-viously discussed, Detroit Edison received rate orders in 2004 that allow for the recovery of increased transmission expenses through the PSCR mechanism. See Note 4 - Regulatory Matters.

Energy Services Energy Services is comprised of Coal-Based Fuels, On-Site Energy Projects and non-utility Power Generation. Coal-Based Fuels operations include producing synthetic fuel from nine synfuel plants and producing coke from three coke battery plants. The production of synthetic fuel from all of our synfuel plants and the production of coke from one of our coke batteries generate tax credits under Section 29 of the Internal Revenue Code. On-Site Energy Projects include pulverized coal injection, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. Power Generation owns and operates four gas-fired peaking electric generating plants and manages and operates two additional gas-fired power plants under contract. Additionally, Power Generation develops, operates and acquires coal and gas-fired generation.

Factors impacting income: Energy Services earnings decreased

$11 million in 2004 and increased $17 million in 2003, compared to the prior year. As subsequently discussed, these results primarily reflect higher gains recognized from selling majority interests in our synfuel plants, varying levels of Section 29 tax credits, a gain from contract termination, uncollectible accounts written-off and losses on synfuel hedges.

2004 annual report 25

(in Millions) 2004 2003 2002 Operating Revenues Coal-Based Fuels On-Site Energy Projects Power Generation - Non-utility Operation and Maintenance Depreciation and Amortization Taxes other than Income Gain on Sale of Interests in Synfuel Projects Operating Income (Loss)

Other (Income) and Deductions Minority Interest Income Taxes Provision (Benefit)

Section 29 Tax Credits Net Income 980 $

96 13 _

1,089 1,188 82 15 (219) 23 (17)

(212) 96 (31) 64 188 $

850 $

70 9

929 1,049 84 18 (83)

(139) 2 (91)

(19)

(230)

(249) 199 $

559 63

_23 645 708 81 15 (40)

(119) 4 (37)

(30)

(238)

(268) 182 Operating revenues increased $160 million in 2004 and $284 million in 2003 reflecting higher synfuel, coal and coke sales, as well as increased revenues from our on-site energy projects.

The improvement in synfuel revenues results from increased production due to additional sales of project interests in 2004 and 2003, reflecting our strategy to produce synfuel primarily from plants in which we had sold interests in order to optinize income and cash flow, As previously discussed, operating expenses associated with syrfuel projects exceed operating revenues and therefore generate operating losses, which have been more than offset by the resulting Section 29 tax credits. When we sell an interest in a synfuel project, we recognize the gain from such sale as the facility produces and sells synfuel and when there is persuasive evidence that the sales proceeds to the Company have become fixed or determinable and collectability is reasonably assured. In substance, we are receiving synfuel gains and reduced operating losses in exchange for tax credits associated with the projects sold.

Synrfuel earnings (in Millions)

Revenues from coke sales were higher in 2004, due to higher coke sales volumes combined with higher market prices, due to limited supplies of coke in the U.S.

Revenues from on-site energy projects increased in 2004, reflecting the completion of new long-term utility services contracts with a large automotive company and a large manufacturer of paper products. Revenues in 2004 include a $9 million pre-tax fee generated in conjunction with the development of a related energy project, 50% of which was sold to an unaffiliated partner.

Operation and maintenance expense increased $139 million in 2004 and $341 million in 2003, reflecting costs associated with synfuel production and coke operations. Partially offsetting the higher synfuel operating costs in 2004 was the recording of insurance proceeds associated with an accident at one of our coke batteries. Operation and maintenance expense in 2003 was affected by a $30 million pre-tax gain from the termination of a tolling agreement at one of our generation facilities, substantially offset by the establishment of a $28 million pre-tax reserve for receivables associated with a large customer that filed for bankruptcy.

Gains on sale of interests in yofelprojects increased $136 million in 2004 and $43 million in 2003. The improvements are due to additional sales of majority interests in our synfuel projects.

To hedge our exposure to the risk of an increase in oil prices that could reduce synfuel sales proceeds, we entered into derivative and other contracts covering approximately 65% of our 2005 synfuel cash flow exposure. The derivative contracts are accounted for under the mark to market method with changes in their fair value recorded as an adjustment to synfuel gains. We recorded a mark to market loss during the 2004 fourth quarter, which reduced 2004 synfuel gains by

$12 million pre-tax See Note 12 for further discussion.

Minority interest increased $121 million in 2004 and $54 million in 2003, reflecting our partners' share of operating losses associated with synfuel operations. The sale of interests in our synfuel facilities during 2004 and 2003 resulted in allocating a larger percentage of such losses to our partners.

Income taxes increased $313 million in 2004 and $19 million in 2003, reflecting higher taxable earnings and a decline in the level of Section 29 tax credits due to the sale of interests in synfuel facilities.

Outlook - Energy Services will continue leveraging its extensive energy-related operating experience and project management capability to develop and grow the on-site energy business. We expect solid earnings from our on-site energy business in 2005 as a result of executing long-term utility services contracts in 2004.

Energy Maiketing & Trading Energy Marketing & Trading consists of the electric and gas marketing and trading operations of DTE Energy Trading and CoEnergy. DTE Energy Trading focuses on physical power marketing and structured transactions, as well as the enhancement of returns from DTE Energy's power plants. CoEnergy focuses on physical gas marketing and the optimization of DTE Energy's owned and contracted natural gas pipelines and gas storage capacity. To this end, both companies enter into derivative financial instruments as part of their marketing and hedging strategies, including forwards, futures, swaps and option contracts. Most of the

$197

$136 U Gains on Synfuel Sales El Section 29 Tax Credits El Operating Losses, net of Minority Interest

$0

[

I.

2002 2003 2004 Coal marketing revenues in 2004 have also been affected by our strategy to produce synfuel primarily from plants in which we had sold interests. This strategy resulted in the reduction of synfuel production levels. We were contractually obligated to supply coal to customers at certain sites that did not produce synfuel as a result of our current production strategy. To meet our obligations to provide coal under long-term contracts with customers, we acquired coal that was resold to customers. The coal was sold at prices higher than the prices at which synfuel would have been sold to these customers.

26 2004 annual report

derivative financial instruments are accounted for under the mark to market method, which results in earnings recognition of unrealized gains and losses from changes in the fair value of the derivatives.

Factors impacting income: Energy Marketing & Trading's earnings increased $47 million in 2004, consisting of a $4 million improvement at DTE Energy Trading and a $43 million improve-ment at CoEnergy. Earnings increased $20 million in 2003, of which $18 million was attributable to DTE Energy Trading and $2 million to CoEnergy.

DTE Energy Trading's earnings improvement in 2004 and 2003 was primarily due to realized margins associated with short-term physical trading and origination activities.

(in Millions) 2004 2003 2002 OTE Energy Trading Margins - Gains (Losses)

Realized (1)

X83 $

82$

38 Unrealized (2):

Proprietary Trading (3)

(7)

Structured Contracts (4) 3 (2) 13 Economic Hedges (5) 11' Total Unrealized Margins (3)

(9) 13 Total Margins 80 73 51 Operating and Other Costs

-'29 28 29 Income Tax Provision 15 13 8

Net Income

$ r36$

32 $

14 CoEnergy Margins - Gains (Losses) (7)

Realized (1)

S -(42) $

168 $

32 Unrealized (2):

ProprietaryTrading (3)

-~

4 9

Structured Contracts (4)

(1)

(1) 22 Economic Hedges (5) 68' (138) 193)

Gas in Inventory (6) 74 Total Unrealized Margins 67 (135) 12 Total Margins 25 33 44 Gain from Contract Modification/Termination (744)

Operating and Other Costs

12 13 27 Income Tax Provision

- i 31 7

6 Net Income 1S

~

56 $

13 $

1 1 Total Energy Marketing

&Trading Net Income iS-92$ $

45 $

25 (1) Realized margins include the settlement of all derivative and non-derivative contracts, as well as the amortization of deferred assets and liabilities.

(21 Unrealized margins include mark-to-market gains and losses on derivative '

contracts, net of gains and losses reclassified to realized. See 'Fair Value of Contracts' section that follows.

(3) Proprietary Trading' represents the net unrealized effect of actively traded positions entered into to take advantage of market price movements.

(4) Structured Contracts represent the net unrealized effect of derivative transactions entered into with the intent to capture profits by originating substantially hedged positions with wholesale energy marketers, utilites, retail aggregators and alternative energy suppliers.

(5) EconomicHedges representthe net unrealized effect of derivative actvity associated with assets owned or contracted for by DTE Energy, including forward sales of gas production and trades associated with transportation and storage capacity.

16)

Gas in inventory margins represent gains associated with fair value accounting in 2002. CoEnergy changed its method of accounting for inventory in January 2003 (Note 2).

(7) Excludes the impact on margins from the modification of a transportation agreement with an interstate pipeline company.

CoEnergys earnings in 2004 and 2003 were affected by varying gains and losses on economic hedge contracts related to storage assets. As subsequently discussed in the 'Outlook" section, the unrealized gains and losses of economic hedge contracts are required to be recognized under mark-to-market accounting, while the offsetting unrealized losses and gains on the underlying asset positions are not recognized.

CoEnergy's earnings in 2004 reflect a $74 million one-time pre-tax gain from modifying a future purchase commitment under a transportation agreement and terminating a related long-term gas exchange (storage) agreement with an interstate pipeline company. Under the gas exchange agreement, we received gas from the customer during the summer injection period and redelivered the gas during the winter heating season.

The realized and unrealized margins comparison for both DTE Energy Trading and CoEnergy was affected by our decision in late 2003 to monetize certain in-the-money derivative contracts while simultaneously entering into replacement at-the-market contracts. The monetizations were completed in corjunction with implementing a series of initiatives to improve cash flow and fully utilize Section 29 tax credits. Although the monetizations did not impact earnings, they had the effect of decreasing realized margins and increasing unrealized margins on economic hedges in 2004, and having the opposite effect on margins in 2003.

Outlook - Energy Marketing & Trading will seek to manage its business in a manner consistent with, and complementary to, the growth of our other business segments.' Gas storage and transportation capacity enhances our ability to provide reliable and custom-tailored bundled services to large-volume end users and utilities. This capacity, -coupled with the synergies from i

DTE Energy's other businesses, positions the segment to add value.

Significant portions of the Energy Marketing & Trading portfolio are economically hedged. The portfolio includes financial instru-ments and gas inventory, as well as owned and contracted natural gas pipelines and storage assets. The financial instruments are deemed derivatives, whereas the gas inventory, pipelines and stor-age assets are not considered derivatives for accounting purposes.

As a result, Energy Marketing & Trading will experience earnings volatility as derivatives are marked to market without revaluing the underlying non-derivative contra6ts and assets. The majority of such earnings volatility is associated with the natural gas storage cycle, which runs annually from April of one year to March of the next year. Our strategy is to economically hedge the'price risk of all gas purchases for storage with sales in the over-the-counter (forwards) and futures markets. Current accounting rules require the marking to market of forward sales and futures, but do not allw'for'the marking to market of th'e irlated gas inventory. This results in gains and losses that are recognized in different interim and annual accounting periods. We anticipate the financial impact of this timing difference will reverse by the end of each storage cycle. See "Fair Value of Contracts' section that follows.

Non-utility - Other Our other non-utility businesses include our Coal Services and Biomass units. Coal Services provides fuel, transportation and rail equipment management services. We specialize in minimizing fuel costs and maximizing reliability of supply for energy-intensive customers. Additionally, we participate in coal trading and 2004 annual report 27

coal-to-power tolling transactions, as well as the purchase and sale of emissions credits. Coal Services has formed a subsidiary, DTE PepTec Inc., which uses proprietary technology to produce high quality coal products from fine coal slurries typically discarded from coal mining operations. Biomass develops, owns and operates landfill recovery systems in the U.S. Gas produced from many of these landfill sites qualifies for Section 29 tax credits.

Factors impacting income: Earnings increased $3 million in 2004 and declined $9 million in 2003. The 2004 increase reflects higher sales from coal and emissions credits, partially offset by increased costs associated with our waste coal operations.

The 2003 decline reflects reduced marketing and tolling income as well as an increase in operating costs associated with ramping up the DTE PepTec business. Our first waste coal facility in Ohio became operational in late 2003.

(Dollars in Millions) 2004 2003 2002 Coal Services Tons of coal shipped (in millions) 39.9 32.0 28.5 Biomass Gas Produced (in Bcf) 23.2' 26.8 27.5 Tax Credits Generated (1) 7.74 $

10.5 $

12.9 (1 DTE Energy's portion of total tax credits generated.

Outlook - We expect to continue to grow our Coal Services and Biomass units. We believe a substantial market could exist for the use of DTE PepTec Inc. technology and we continue to modify and prove out this technology. Coal Services and Biomass have formed a new subsidiary to enter the coal mine methane business. Ae purchased coal mine methane assets in Illinois at the end of 2004, and expect to reconfigure equipment and restart operations by mid-2005.

The Section 29 tax credits generated by Biomass are subject to the same phase out risk if domestic crude oil prices reach certain levels, as detailed in the synthetic fuel operations discussion. See Note 13.

ENERGY DISTRIBUTION Utility - Power Distribution Power Distribution operations include the electric distribution services of Detroit Edison. Power Distribution distributes electric-ity generated and purchased by Energy Resources and alternative energy suppliers to Detroit Edison's 2.1 million customers.

Factors impacting income: Power Distribution earnings increased

$71 million during 2004 and decreased $94 million in 2003, compared to the prior year. As subsequently discussed, these results primarily reflect varying operating revenues and operation and maintenance expenses, as well as a non-recurring loss recorded in 2003.

(in Millions) 2004 2003 2002 Operating Revenues

$ 1,358 $

1,247 $ 1,343 Fuel and Purchased Power 17' 19 26 Operation and Maintenance 723t 724 649 Depreciation and Amortization 251 249 246 Taxes OtherThan Income 101 100 117 Operating Income 266 155 305 Other (Income) and Deductions 137.

128 136 Income Tax Provision 41 10 58 NetIncome S

88 $

17 $

111 (in Thousands of MM) 2004 2003 2002 Electric Deliveries Residential 15,08VI 15,074 15,958 Commercial 13,4251i 15,942 18,395 Industrial

1,472 12,254 13,590 Wholesale 2.197T.

2,241 2,249 Other 401 402 403 2.576 45,913 50,595 Electric Choice 9,245 6,193 2,967 Electric Choice -Self Generations*

595 1,088 543 Total Electric Deliveries 52416 53,194 54,105

Represents deliveries for self generators who have purchased power from alternative energy suppliers to supplement their power requirements.

Operating revenues increased $111 million in 2004, primarily due to an increase in base rates resulting from the interim and final rate orders. The 2004 improvement is also attributable to residential sales growth and the allocation of a higher portion of Detroit Edison's billings to Power Distribution, partially offset by the effects of milder weather. Operating revenues decreased

$96 million in 2003, reflecting mild summer weather and the impact of slower economic conditions.

Operation and maintenance expense decreased $1 million in 2004 and increased $75 million in 2003. The operation and maintenance expense comparability was affected by 2003 restoration costs associated with three catastrophic storms and the August 2003 blackout. Both years were also affected by an increase in reserves for uncollectible accounts receivable, reflecting high past due amounts attributable to economic conditions, and an increase in employee benefit costs. Additionally, the comparisons were affected by incremental costs associated with our DTE2 project implementation, a $22 million pre-tax loss in 2003 from the sale of our steam heating business, and the accrual of refunds in 2004 and 2003 associated with transmission services.

Storm Restoration Costs (in Millions)

$72

$48'I-

I-7_-0 J"

-V.

rm

!i, I

a MMEE 2002 2003 2004 Outlook - Operating results are expected to vary as a result of external factors such as weather, changes in economic conditions and the severity and frequency of storms.

We experienced numerous catastrophic storms over the past few years. The effect of the storms on annual earnings was partially offset by storm insurance. We have been unable to obtain storm insurance at economical rates and as a result, we do not anticipate having insurance coverage at levels that would significantly offset unplanned expenses from ice storms, tornadoes, or high winds that damage our distribution infrastructure.

Non-Utility Non-utility Energy Distribution operations consist of DTE Energy Technologies, which assembles, markets, distributes and services distributed generation products, provides application engineering, and monitors and manages on-site generation system operations.

Operating Income as a Percent of Operating Revenues 20%

12%

23%

28 2004 annual report 11

Factors impacting income: Non-utility results declined

$4 million in 2004 and improved $1 million in 2003. The 2004 decrease includes an impairment charge for an "other than temporary" decline in the fair value of an investment in a joint venture that supplied certain distributed generation equipment and materials to DTE Energy Technologies.

Outlook - DTE Energy Technologies will focus on sales of proprietary pre-engineered and packaged continuous generation products in key applications. This will likely result in near-term revenue decline, but we anticipate gross profit margins will improve. Combined with continuing cost reductions and resumption of sales growth, we believe these actions will lead to improved financial performance in 2005.

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

Factors impacting income: Gas Distribution's earnings declined

$9 million in 2004 and $37 million in 2003, compared to the prior year. As subsequently discussed, results primarily reflect varying gross margins, higher operation and maintenance expenses and a non-recurring loss recorded in 2003.

(in Millions) 2004 2003 2002 tin BcIt 2004 2003 2002 Gas Markets Gas sales

173 181 174 End usertransportation

.145 152 171 318 333 345 Intermediate transportation 536 576 492 8:54 909 837 Operation and maintenance expense increased $29 million in 2004 and $74 million in 2003, reflecting higher reserves for uncollectible accounts receivable and pension and health care costs. The increase in uncollectible accounts expense reflects high past due amounts attributable to an increase in gas prices, continued weak economic conditions and a lack of adequate public assistance for low-income customers.

Uncollectible Accounts Expense (in Millions)

I `+ '$21`. A I F-

$60 2002 2003 2004 Operating Revenues M Ile Cost of Gas i.

Gross Margins t

Operation and Maintenance 4

Depreciation and Amortization

-1 Taxes Other Than Income Operating Income Other (income) and Deductions Income Tax Provision (Benefit)

Net Income Operating Income as a Percent of Operating Revenues Gross margins increased $22 million in X

$6 million in 2003, compared to the prioi 2004 reflects the impact of interim rate i from the acceleration of several midstre, Partially offsetting these improvements v user transportation deliveries due to mili margin comparison was also affected by; reserve recorded in 2003 for the potentia pursuant to an MPSC order in MichCon's (GCR) plan case (Note 4). Operating rev increased significantly in 2004 and 2003:

which are recoverable from customers tt 82 $

1,498 $ 1,369 Other income and deductions expense increased $12 million in 711 909 774 2004 and decreased $5 million in 2003, reflecting a 2003 gain on 11 589 595 sale of interests in a series of real estate partnerships.

00 371 297 Income taxes in 2004 and 2003 were impacted by lower earnings 03 101 104 and favorably affected by an increase in the amortization of tax 49 52 51 benefits previously deferred in accordance with MPSC regulations.

59 65 143 Outlook - Operating results are expected to vary as a result of

.48 36 41 external factors such as regulatory proceedings, weather and

{9) 36 changes in economic conditions. Higher gas prices and economic 20 $

29 $

66 conditions have resulted in an increase in past due receivables.

We believe our allowance for doubtful accounts is based on 4

reasonable estimates. However, failure to make continued 2004 and decreased progress in collecting past due receivables would unfavorably year. The improvement in affect operating results. Energy assistance programs funded by relief and additional margin the federal government and the State of Michigan remain critical am services Contracts.

to MichCon's ability to control uncollectible accounts receivable vere lower sales and end expenses. We are working with the State of Michigan and others Jer weather. The gross to increase the share of funding allocated to our customers to a $26.5 million pre-tax be representative of the number of low-income individuals in aI disallowance in gas costs our service territory.

2002 gas cost recovery

enues and cost of gas reflecting higher gas prices, urough the GCR mechanism.

(in Millions}

2004 2003 2002 Gas Markets Gas sales t$ A1.435 $

1,242 $ 1,135 End usertransportation 1 119 136 122 1,554 1,378 1,257 Intermediate transportation

, -56 51 48 Other 72 69 64 S 1,682 $

1,498 $ 1,369 As a result of the continued increase in operating costs, MichCon filed a rate case in September 2003 to increase rates by $194 million annually to address future operating costs and other issues. MichCon received an interim order in this rate case in September 2004 increasing rates by $35 million annually.

The MPSC Staff has recommended a provision that would allow MichCon to recover or refund 90% of uncollectible accounts receivable expense above or below the amount that is reflected in base rates. See Note 4 - Regulatory Matters.

2004 annual report 29

Non-utility Non-utility operations include the Gas Production business and the Gas Storage, Pipelines & Processing business. Our Gas Production business produces gas from proven reserves in northern Michigan and sells the gas to the Energy Marketing & Trading segment.

Gas Storage, Pipelines & Processing has a partnership interest in an interstate transmission pipeline, seven carbon dioxide processing facilities and a natural gas storage field, as well as lease rights to another natural gas storage field. The assets of these businesses are well integrated with other DTE Energy entities.

Factors impacting income: Earnings decreased $8 million in 2004 and increased $3 million in 2003. The decline in 2004 is due to gains recorded in 2003 from selling our 16% pipeline interest in the Portland Natural Gas Transmission System, as well as from selling certain gas properties. Excluding those gains, income increased $2 million reflecting the acquisition of an additional 15% ownership in the Vector Pipeline in late 2003, increased sales of transportation capacity by Vector Pipeline and increased storage sales throughout 2004.

Outlook - We anticipate further expansion of our storage facilities and Vector pipeline to take advantage of available growth opportunities. We are also seeking to secure markets for our 10.5% interest in the Millennium Pipeline.

We expect to continue developing our gas production properties in northern Michigan and leverage our experience in this area by pursuing investment opportunities in unconventional gas production outside of Michigan. During 2004, we acquired approximately 50,000 leasehold acres in the southern region of the Barnett shale in Texas, an area of increasing production.

We began drilling test wells in December 2004 and anticipate drilling a significant number of additional test wells in the first half of 2005. Initial results from the test wells are expected in mid-2005. If the results are successful, we could commit up to $350 million of capital over the next several years to develop these properties.

CORPORATE & OTHER Corporate & Other includes various corporate support functions such as accounting, legal and information technology. As these functions essentially support the entire Company, their costs are fully allocated to the various segments based on services utilized and therefore the effect of the allocation on each segment can vary from year to year. Additionally, Corporate & Other holds certain non-utility debt and investments, including assets held for sale and in emerging energy technologies.

Factors impacting income: Corporate & Other results improved

$47 million in 2004, compared to a $1 million decline in 2003.

The 2004 improvement was affected by a $14 million net of tax gain from the sale of 3.5 million shares of Plug Power stock (Note 1), as well as lower Michigan Single Business Taxes, resulting from tax saving initiatives. Results for 2003 include a $15 million cash contribution to the DTE Energy Foundation, funded with proceeds received from the sale of ITC. Corporate & Other also benefited from lower financing costs and increased intercompany interest income in both periods.

DISCONTINUED OPERATIONS Southern Missouri Gas Company (SMGC) - We own SMGC, a public utility engaged in the distribution, transmission and sale of natural gas in southern Missouri. In 2004, management approved the marketing of SMGC for sale. Under U.S. generally accepted accounting principles, we classified SMGC as a discontinued operation in 2004 and recognized a net of tax impairment loss of approximately $7 million, representing the write-down to fair value of the assets of SMGC, less costs to sell, and the write-off of allocated goodwill. In November 2004, we entered into a definitive agreement providing for the sale of SMGC. Following receipt of regulatory approvals and resolution of other contingencies, it is anticipated that the transaction will close in 2005.

International Transmission Company - In February 2003, we sold ITC, our electric transmission business, to affiliates of Kohlberg Kravis Roberts & Co. and Trimaran Capital Partners, LLC. Accordingly, we classified ITC as a discontinued operation.

The sale generated a preliminary net of tax gain of $63 million in 2003. The gain was net of transaction costs, the portion of the gain that was refundable to customers and the write off of approxi-mately $44 million of allocated goodwill. The gain was lowered to $58 million in 2004 under the MPSC's November 2004 final rate order that resulted in a revision of the applicable transaction costs and customer refund. W'e had income from discontinued operations of $5 million in 2003.

See Note 3 for further discussion.

CUMULATIVE EFFECT OF ACCOUNTING CHANGES As required by U.S. generally accepted accounting principles, on January 1, 2003, we adopted new accounting rules for asset retirement obligations and energy trading activities. The cumula-tive effect of adopting these new accounting rules reduced 2003 earnings by $27 million. See Note 2 for further discussion.

CAPITAL RESOURCES AND LIQUIDITY DTE Energy and its subsidiaries require cash to operate and cash is provided by both internally and externally generated sources.

We manage our liquidity and capital resources to maintain financial flexibility to meet our current and future cash flow needs, Cash Requirements Wle use cash to maintain and expand our electric and gas utilities and to grow our non-utility businesses, in addition to retiring and paying interest on long-term debt and paying dividends.

Our strategic direction anticipates base level capital investments and expenditures for existing businesses in 2005 of up to

$1.1 billion. The capital needs of our utilities will increase due primarily to environmental related expenditures.

Capital spending for general corporate purposes will increase in 2005, primarily as a result of DTE2 and environmental spending. We began implementing the DTE2 project in 2003.

The Company expects the project to incrementally cost approximately $160 million to $175 million.

The EPA ozone transport regulations and final new air quality standards relating to ozone and particulate air pollution will continue to impact us. Detroit Edison estimates that it will spend approximately $100 million in 2005 and incur up to an additional

$1.3 billion of future capital expenditures over the next five to eight years to satisfy both existing and proposed new control requirements. The full recovery of $550 million of environmental expenditures was authorized in the MPSC's November 2004 final rate order.

30 2004 annual report 1I

Non-utility capital spending will approximate $100 million to

$300 million annually for the next several years. Capital spending for growth of existing or new businesses will depend on the existence of opportunities that meet our strict risk-return and value creation criteria.

Debt maturing in 2005, excluding securitization debt, totals approximately $410 million.

We believe that we will have sufficient internal and external capital resources to fund anticipated capital requirements.

(in Millions) 2004 2003 2002; Cash and Cash Equivalents Cash Flow From (Used For)

Operating activities:

Net income

$ -431 521 $

632 Depreciation, depletion and amortization 744 691 759 Deferred income taxes 129 (220)

(208)

Gain on sale of ITC, synfuel and other assets, net (236)

(228)

(40)

Working capital and other

' -(73) 186 (147) 995 950 996 Investing activities:

Plant and equipment expenditures - utility (815)

(679)

(794)

Plant and equipment 1' ir-expenditures -non-utility (89)

(72)

(190)

Investment in joint ventures (36)

(34)

(21)

Proceeds from sale of ITC, V.l synfuels and other assets If i k325 758 41 Restricted cash and other investments (66) 37 (151)

(681) 10 (1,115)

Financing activities:

I t

Issuance of long-term debt and common stock

777, 571 1,403 Redemption of long-term debt (759)

(1,208)

(793)

Short-term borrowings, net 33 (44)

(267)

Dividends on common stock and other (363)

(358)

(359)

(312)

(1,039)

(16)

Net Increase (Decrease) in Cash and Cash Equivalents 1$

`'2 $

(79) $

(135)

Cash from Operating Activities A majority of the Company's operating cash flow is provided by our two utilities, which are significantly influenced by factors such as weather, electric Customer Choice sales loss, regulatory deferrals, regulatory outcomes, economic conditions and operating costs.'

Our non-utility businesses also provide sources of cash flow to the enterprise and reflect a range of operating profiles. The profiles vary from our synthetic fuels business, which we believe will provide over $1.6 billion in cash through 2008,' to new start-ups:I These new start-ups include our unconventional gas'and waste coal recovery businesses, which we are growing and, if successful, could require significant investments.

Although DTE Energ"ys overall earnings'were $431 million in 2004, cash from operations totaling $995 million was up $45 milion from the comparable 2003 period. The operating cash flow comparison reflects an increase of over $300 million in net income, after adjusting for non-cash items (depreciation, depletion, amortization, deferred taxes and gains), substantially offset by a $259 million increase in working capital and other requirements. A portion of this improvement is attributable to the change in our strategy to primarily produce synfuel from plants in which we have sold interests. As previously discussed, synfuel projects generate operating losses, which have been more than offset by tax credits that we have been unable to fully utilize, thereby negatively affecting operating cash flow. Cash for working capital primarily reflects higher income tax payments of $172 million in 2004, reflecting a different payment pattern of taxes in 2004 compared to 2003. The increase in working capital was mitigated by Company initiatives to improve cash flow, including better inventory management, cash sales transactions, deferral of retirement plan contributions and the utilization of letters of credit.

Certain cash initiatives in 2003 lowered cash flow in 2004.

Our net operating cash flow in 2003 was $950 million, reflecting a $46 million decline from 2002. The decrease was attributable to lower utility net income, after adjusting foir non-cash items.

Partially offsetting the declines were lower working capital and other requirements reflecting Company initiatives to improve cash flow and optimize synfuel operations. The improvement in 2003 working capital was achieved despite a $222 million contribution to our pension plans.

Outlook - We expect cash flow from operations to increase over the long-term primarily due to improvements from utility rate increases and the sales of interests in our synfuel projects.

This'will be partially offset by higher cash requirements,' primarily within our gas storage business. We are continuing our efforts to identify opportunities to improve cash flow through cash improvement initiatives.

Operating cash flow from our utilities is expected to increase in 2005, but will be affected by the level of sales migration under the electric Customer Choice program and the ability of the MPSC within the regulatory processes to put in place a Custo6mer Choice program that has sound economic fundamentals. In addition, the rora.

me

,the.,

Customer Choice program's impact will also be determined by the success of the Company in addressing certain structural flaws within additional regulatory proceedings and the legislative process.

Another factor affecting utility cash flows is the degree and timing of rate relief within the electric and gas rate cases.

Based on the final and interim orders issued by the MPSC in 2004, approximately $50 miiion of additional revenues were'realized in the 2004 calendar year. Due to the structure 'of the inteim and final rate orders, we will not realizie'the full benefitsof interlim and finalrate relief until 2006 when all customer rate caps expire.

Improvements in cash flow from our utilities are also expected from better management of our working capital requirements, including the c6ntinued focus on' reducing past due accounts receivable. Our emphasis in these businesses'will continue to be centered around cash generation and conservati'on.

Cash flows from our synfuel business are expected to total approxi-mately $1.6 billion between 2005 and 2008. The redeployment of this cash represents a unique opportunity to increase shareholder value and strengthen our balance sheet. We expect to use this cash to reduce debt, to continue to pursue growth investments that meet 2004 annual report 31

our strict risk-return and value creation criteria and to potentially repurchase common stock if adequate investment opportunities are not available. Our objectives for cash redeployment are to strengthen the balance sheet and coverage ratios in order to improve our current credit ratings and outlook, and to more than replace the value of synfuels.

Cash flows from our synfuel business are expected to approximate

$400 million in 2005. The source of synfuel cash flow includes cash from operations (excluding certain working capital changes), asset sales, and the utilization of Section 29 tax credits carried fonvard from synfriel production prior to 2004.

Our other operating non-utility businesses are expected to contribute approximately $400 million through 2008.

Remaining start-up businesses such as unconventional gas production, waste coal recovery and distributed generation will continue to use cash in excess of their cash generation over the next couple of years while they are being further developed.

Certain of the previously discussed cash initiatives resulted in accelerating the receipt of cash in 2004, which will have the impact of lowering cash flow in 2005.

Cash from Investing Activities Cash inflows associated with investing activities are primarily generated from the sale of assets. In any given year, we will look to harvest cash from under performing or non-strategic assets.

Capital spending within the utility business is primarily to main-tain our generation and distribution infrastructure, comply with environmental regulations and gas pipeline replacements. Capital spending within our non-utility businesses is for ongoing mainte-nance and some expansion. The balance of non-utility spending is for growth, which we manage very carefully. We look to make investments that meet strict criteria in terms of strategy, manage-ment skills, risks and returns. All new investments are analyzed for their rates of return and cash payback on a risk adjusted basis.

WMe have been disciplined in how we deploy capital and will not make investments unless they meet our criteria. For new business lines, we invest tentatively based on research and analysis. Based on a limited investment, we evaluate results and either expand or exit the business based on those results. In any given year, the amount of growth capital will be determined by the underlying cash flows of the Company with a clear understanding of any potential impact on our credit ratings.

Net cash relating to investing activities declined $691 million in 2004 and improved $1.1 billion in 2003, compared to the prior year.

The changes were primarily due to proceeds received in 2003 total-ing $758 million from the sale of ITC, interests in three synfuel projects and non-strategic assets. Additionally, the changes are due to variations in cash contractually designated for debt service.

Longer term, with the expected improvement at our utilities and continued cash generation from the synfuel business, cash flows are expected to improve. We will continue to pursue opportunities to grow our businesses in a disciplined fashion if we can find opportunities that meet our strategic, financial and risk criteria.

Cash from Financing Activities We rely on both short-term borrowings and longer-term financings as a source of funding for our capital requirements not satisfied by the Company's operations. Short-term borrowings, which are mostly in the form of commercial paper borrowings, provide us with the liquidity needed on a daily basis. Our commercial paper program is supported by our unsecured credit facilities.

DTE Energy and its subsidiaries have a total of $1.675 billion in credit facilities, which provide liquidity to our commercial paper programs and support the use of letters of credit.

(in Millions)

FacilityAmount Maturity Date Issuing Entity DTE Energy 375.00 5/5/2006 DTE Energy 175.00 10/24/2006 DTE Energy 525.00 10/15/2009 Detroit Edison 68.75 10/24/2006 Detroit Edison 206.25 10/15/2009 MichCon 81.25 10/24/2006 MichCon 243.75 10/15/2009 1,675.00 Borrowings under the facilities are available at prevailing short-term interest rates. The agreements require each of the Companies to maintain a debt to total capitalization ratio of no more than.65 to 1 and an "earnings before interest, taxes, depreciation and amortization" (EBITDA) to interest ratio of no less than 2 to 1. DTE Energy has significant room under these provisions, with coverage totaling 4.3 to 1 and leverage at.489 to I at December 31, 2004. The Companies are currently in compliance with these financial covenants. Should either Detroit Edison or AlichCon have delinquent debt obligations of at least $25 million to any creditor, such delinquency will be considered a default under DTE Energy's credit agreements.

These agreements have standard material adverse change (MAC) clauses, however, the agreements expiring in October 2009 include a provision that the MAC clause does not apply when borrowings are made to repay maturing commercial paper.

Additionally, Detroit Edison has a $200 million short-term financing agreement secured by customer accounts receivable.

The agreement contains certain covenants related to the delinquency of accounts receivable. Detroit Edison is currently in compliance with these covenants.

For additional information see Note 10 -Short-Term Credit Arrangements and Borrowings.

Our strategy is to have a targeted debt portfolio blend as to fixed and variable interest rates and maturity. We continually evaluate our leverage target, which is currently 50% or lower, to ensure it is consistent with our objective to have a strong investment grade debt rating. We have completed a number of refinancings with the effect of extending the average maturity of our long-term debt and strengthening our balance sheet.

The extension of the average maturity was accomplished at interest rates that lowered our debt costs.

Net cash used for financing activities improved $727 million in 2004 and declined $1.0 billion in 2003, compared to the prior periods.

The 2004 change was primarily due to higher issuances of new long and short-term debt and fewer repurchases of long-term debt.

The 2003 change was due to higher redemptions of long-term debt and lower proceeds from issuances of new debt and common stock For additional information on debt issuances and redemptions, see Note 9 -Long-Term Debt and Preferred Securities.

32 2004 annual report 11

Amounts available under shelf registrations include $500 million at DTE Energy and $150 million at Detroit Edison. MichCon does not have current shelf capacity. In 2005, we plan on filing new shelf registration statements for MichCon and Detroit Edison.

Common stock issuances or repurchases can also be a source or use of cash. In January 2005, we announced the DTE Energy Board has authorized the repurchase of up to $700 million in' common stock through 2008. The authorization provides Compay management with flexibility to pursue share repurchases from time to time, and will depend on future cash flows and investment opportunities. In January 2005, we discontinued issuing new DTE Energy shares for our dividend reinvestment plan, which generated approximately $50 million annually. We also contributed $170 million of DTE Energy common stock to our pension plan in the first quarter of 2004.

Contractual Obligations The following table details our contractual obligations for debt redemptions, leases, purchase obligations and other long-term obligations as of December 31, 2004:

We have issued guarantees for the benefit of various non-utility subsidiaries. In the event that our credit rating is downgraded to below investment grade, certain of these guarantees would require us to post cash'or letters of credit valued at approximately $356 million at December 31, 2004. Additionally, our trading business could be required to restrict operations and our access to the short-term commercial paper market could be restricted or eliminated.

While we currently do not anticipate such a downgrade, we cannot predict the outcome of current or future reviews. The following table shows our credit rating as determined by three nationally respected credit rating agencies. AU ratings are considered investment grade and affect the value of the related securities.

Entity Description DTE Energy Senior Unsecured Debt Commercial Paper Detroit Edison Senior Secured Debt Commercial Paper MichCon Senior Secured Debt Commercial Paper

Currently on negative outlook Standard

& Poors BBB-A-2 BBB+

A-2 BBB A-2 Credit Rating Agency Moody's Investors Service Baa2

P-2*

A3*

p-2*

A3 P-2 Fitch Ratings BBB F2 A-F2 A-F2 Less Than 1-3 al 1 Year Years 4-5 After Years 5 Years On Millions)

Tot Contractual Obligations Long-Term Debt Mortgage bonds, notes & other

$ 6,0' Securitization bonds 1A, Equity-linked securities 1

Trust preferred-linked securities 21 Capital lease obligations Interest 6,3 Operating leases 6;

Electric, gas, fuel, transportation & storage purchase obligations*

6,1:

Other long-term obligations 3'

91 S 410 $ 1,224 S 759 $ 3,698 36 78 96 5

335 173 272 793 39 34 23 30 11 494 64 34 1,280 143 20 726 75 289 29 3,846 341 3,694 1,601 236 599 57 97 151 37 72 Total Obligations

$ 21,604 $ 4,871 $ 4,941 $ 2,125 $ 9,667

Excludes amounts associated with full requirements contracts where no stated minimum purchase volume is required.

Credit Ratings Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and not a recommendation to buy, sell or hold securities. Management believes that the current credit ratings of the Company provide sufficient access to the capital markets.

However, disruptions in the banking and capital markets not specifically related to DTE Energy may affect the Company's ability to access these funding sources or cause an increase in the return required by investors.

In November 2004, Moody's Investors Service and Fitch Ratings downgraded MichCon. In December 2004, Standard & Poor's downgraded DTE Energy, Detroit Edison and MichCon. The ratings reflect weaker credit metrics due to decreased cash flows mainly stemming from increased operation and maintenance costs without sufficient regulatory relief. Additional unfavorable changes in our ratings could restrict our ability to access capital markets at attractive rates and increase our borrowing costs.

CRITICAL ACCOUNTING ESTIMATES There are estimates used in preparing the consolidated financial statements that require considerable judgment. Such estimates relate to regulation, risk management and trading activities, Section 29 tax credits, goodwill, pension and postretirement costs, the allowance for doubtful accounts, and legal and tax reserves.

Regulation A significant portion of our business is subject to regulation.

Detroit Edison and MichCon currently meet the criteria of Statement of Financial Accounting Standards (SFAS) No. 71, "Accountingfor the Effects of Certain ljrpes of 1egulationg" Application of this standard results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses. SFAS No. 71 requires the recording of regulatory assets and liabilities for certain transactions that wotild have been treated as revenue or expense in non-regulated businesses. Future regulatory changes or changes in the competitive environment could result in discontinuing the application of SFAS No. 71 for some or all of our businesses. If we were to discontinue the application of SFAS No. 71 on all our operations, we estimate that the extraordinary loss would be as follows:

ran Millions) utility Detroit Edison*

(138)

MichCon (42)

Total (180)

Excludes securitized regulatory assets Management believes that currently available facts support the continued application of SPAS No. 71 and that all regulatory assets and liabilities are recoverable or refundable in the current rate environment (Note 4).

2004 annual report 33

Risk Management and Trading Activities All derivatives are recorded at fair value and shown as "Assets or liabilities from risk management and trading activities" in the consolidated statement of financial position. Risk management activities are accounted for in accordance with SFAS No. 133, "Accountingf or Derivative Instruments and Hedging Activities,"

as amended. Through December 2002, trading activities were accounted for in accordance with Financial Accounting Standards Board (FASB) Emerging Issues Task Force (EITF) Issue No. 9810, "Accountingfor Energy Rlading and Risk Management Activities." Effective January 2003, trading activities are accounted for in accordance with SFAS No. 133.

See Note 2 -New Accounting Pronouncements.

The offsetting entry to "Assets or liabilities from risk management and trading activities" is to other comprehensive income or earn-ings depending on the use of the derivative, how it is designated and if it qualifies for hedge accounting. The fair values of derivative contracts were adjusted each reporting period for changes using market sources such as:

published exchange traded market data

prices from external sources

price based on valuation models Market quotes are more readily available for short duration contracts. Derivative contracts are only marked to market to the extent that markets are considered highly liquid where objective, transparent prices can be obtained. Unrealized gains and losses are fully reserved for transactions that do not meet this criterion.

Section 29 Tax Credits We generate Section 29 tax credits from our synfuel, coke battery and biomass operations. We recognize earnings as tax credits are generated at our facilities in one of two ways. First, to the extent we generate credits to our own account, we recognize earnings through reduced tax expense. Second, to the extent we have sold an interest in our synfuel facilities to third parties, we recognize gains as synfuel is produced and sold, and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectibility is reasonably assured.

All Section 29 tax credits taken after 1997 are subject to audit by the IRS, however, all of our synthetic fuel facilities have received favorable private letter rulings from the IRS with respect to their operations. Audits of four of our synfuel facilities for the years 2001 and 2002 were successfully completed during 2004. One synfuel facility is currently under audit If our Section 29 tax credits were disallowed in whole or in part as a result of an IRS audit, there could be a significant write-off of previously recorded earnings from such tax credits.

Tax credits generated by our facilities were $449 million in 2004, as compared to $387 million in 2003 and $351 million in 2002.

The portion of tax credits generated for our own account were $38 million in 2004, as compared to $241 million in 2003 and $250 million in 2002, with the remaining credits generated allocated to third party partners. Outside firms assist us in assuring we operate in accordance with our private letter rulings and within the parameters of the law, as well as calculating the value of tax credits.

Goodwill Certain of our business units have goodwill resulting from purchase business combinations (Notes 2 and 16). In accordance with SFAS No. 142, "Goodwill and Other Intangible Assets," each of our 34 2004 annual report reporting units with goodwill is required to perform impairment tests annually or whenever events or circumstances indicate that the value of goodwill may be impaired. In order to perform these impairment tests, we must determine the reporting unit's fair value using valuation techniques, which use estimates of discounted future cash flows to be generated by the reporting unit. These cash flow valuations involve a number of estimates that require broad assumptions and significant judgment by management regarding future performance. To the extent estimated cash flows are revised downward, the reporting unit may be required to write down all or a portion of its goodwill, which would adversely impact our earnings.

As of December 31, 2004, our goodwill totaled $2.1 billion. The majority of our goodwill is allocated to our utility reporting units, with approximately $772 million allocated to the utility Energy Gas reporting unit. The value of the utility reporting units is signifi-cantly impacted by rate orders and the regulatory environment.

The utility Energy Gas reporting unit is comprised primarily of MichCon. We have made certain cash flow assumptions for MichCon that are dependent upon the successful outcome of the outstanding gas rate case (Note 4). These assumptions may change when we receive a final rate order, which is expected during the first quarter of 2005.

Based on our 2004 goodwill impairment test, we determined that the fair value of our reporting units exceed their carrying value and no impairment existed. We will continue to monitor regulatory events, and evaluate their impact on our valuation assumptions and the carrying value of the related goodwill.

While we believe our assumptions are reasonable, actual results may differ from our projections.

Pension and Postretirement Costs Our costs of providing pension and postretirement benefits are dependent upon a number of factors, including rates of return on plan assets, the discount rate, the rate of increase in health care costs and the amount and timing of plan sponsor contributions.

We had pension costs for qualified pension plans of $81 million in 2004, $47 million in 2003, and pension income of $9 million in 2002. Postretirement benefits cost for all plans were $125 million in 2004, $118 million in 2003, and $70 million in 2002. Pension and postretirement benefits cost for 2004 is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on our plan assets of 9.0%. In developing our expect-ed long-term rate of return assumption, we evaluated input from our consultants, including their review of asset class risk and return expectations as well as inflation assumptions. Projected returns are based on broad equity and bond markets. Our expected long-term rate of return on plan assets is based on an asset allocation assumption utilizing active investment management of 65% in equity markets, 28% in fixed income markets, and 7% invested in other assets. Because of market volatility, we periodically review our asset allocation and rebalance our portfolio when considered appropriate. Given market conditions, we believe 9.0% is a reasonable long-term rate of return on our plan assets.

We will continue to evaluate our actuarial assumptions, including our expected rate of return, at least annually.

We base our determination of the expected return on qualified plan assets on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes changes in fair value in a systematic manner over a three-year 1I

period. Because of this method, the future value of assets will be impacted as previously deferred gains or losses are recorded. We have unrecognized net gains due to the recent favorable perform-ance of the financial markets. As of December 31, 2004, we had

$63 million of cumulative gains that remain to be recognized in the calculation of the market-related value of assets.

The discount rate that we utilize for determining future pension and postretirement benefit obligations is based on a review of bonds that receive one of the two highest ratings given by a recog-'

nized rating agency. The discount rate determined on this basis has decreased from 6.25% at December 31, 2003 to 6.0% at December 31, 2004. Due to recent financial market performance, lower discount rates and increased health care trend rates, we estimate that our 2005 pension costs will approximate $96 million compared to $81 million in 2004 and our 2005 postretirement benefit costs will approximate $155 million compared to $125 million in 2004.

In the last several years we have made modifications to the pension and postretirement benefit plans to mitigate the earnings impact of higher costs. Future actual pension and postretirement benefit costs will depend on future investment performance, changes in future discount rates and various other factors related to plan design. Additionally, future pension costs for Detroit Edison will be affected by a pension tracking mechanism, which was authorized by the MPSC in its November 2004 rate order. The tracking mecha-nism provides for the recovery or refunding of pension costs above or below the amount reflected in Detroit Edison's base rates.

Lowering the expected long-term rate of return on our plan assets by 1.0% would have increased our 2004 qualified pension costs by approximately $24 million. Lowering the discount rate and the salary increase assumptions by 1.0% would have, increased our pension costs for 2004 by approximately $8 million.

Lowering the health care cost trend assumptions by 1.0% would have decreased our postretirement benefit service and interest costs for 2004 by approximately $17 million.

The market value of our pension and postretirement benefit plan assets has been affected by the financial markets. The value of our, plan assets increased from $2.4 billion at December 31, 2002 to

$2.9 billion at December 31, 2003. The value at December 31, 2004 increased to $3.3 billion. The investment performance returns and declining discount rates required us to recognize an additional minimum pension liability, an intangible asset and an entry to other comprehensive loss (shareholders' equity) at December 2002, 2003 and 2004. The additional minimum pension liability.

and related accounting entries will be reversed on the balance sheet in future periods if the fair value of plan assets exceeds the accumulated pension benefit obligations. The recording of the minimum pension liability does not affect net income or cash flow.

Pension and postretirement costs and pension cash funding requirements may increase in future years without substantial returns in the financial markets. We made a $35 million cash contribution to the pension plan in 2002, a $222 million cash contribution in 2003 and a $170 million contribution to our pension plan in the form of DTE Energy common stock in 2004.

We also contributed $33 million to the postretirement plans in 2002 and contributed $80 million to the postretirement plans in 2004. We did not contribute to the postretirement plans in 2003.

We do not anticipate making a contribution to our qualified pension plans in 2005. At the discretion of management, we anticipate making a $0 to $40 million contribution to our postretirement plans in 2005.

In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act was signed into law. This Act provides for a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the benefit established by law. The effects of the subsidy on the measurement of net periodic postretirement benefit costs reduced costs by $16 million in 2004.

See Note 14 - Retirement Benefits and Trusteed Assets for a further discussion of our pension and postretirement benefit plans.

Allowance for Doubtful Accounts We establish an allowance for doubtful accounts based upon factors surrounding the credit risk of specific customers, historical trends; economic conditions, age of receivables and other information. Higher customer bills due to increased gas prices,the lack of adequate levels of assistance for low-income customers and economic conditions have also contributed to the increase in past due receivables. As'a result of these factors, our allowance for doubtful accounts increased in 2003 and 2004.

We believe the allowance for doubtful accounts is based on reasonable estimates. However, failure to make continued progress' in collecting our past due receivables would unfavorably affect operating results and cash flow.

Legal and Tax Reserves We are involved in legal and tax proceedings, claims and litigation arising in the ordinary course of business. We regularly assess our liabilities and contingencies in connection with asserted or potential matters, and establish reserves when appropriate.

Legal reserves are based upon management's assessment of pending and threatened legal proceedings against the Company.

Tax reserves are based upon management's assessment of potential adjustments to tax positions taken. We regularly review ongoing tax audits and prior audit experience, in addition to current tax and accounting authority in assessing potential adjustments.

ENVIRONMENTAL MATTERS Protecting the environment, as well as correcting past environmental damage, continues to be a focus of state and federal regulators. Legislation and/or rulemaking could further impact'the electric utility industry including Detroit Edison.

The Envir6nmental Protection Agency (EPA) and the Michigan Department of Environmental Quality have aggressive programs to clean-up contaminated property.

Air - The EPA ozone transport and acid rain regulations and final new air quality'standards relating to ozone and particulate air pollution Wvill continue to impact us. Detroit Edison has spent approximately $580 million through December 2004 and estimates that it will spend up to $100 million in 2005. Detroit Edison estimates it will incur fromn $700 million to $1.3 billion of additional future capital expenditures over the next five to eight years to satisfy both existing and proposed new control requirements. Recovery of costs to be incurred through December 2004 was provided for in our November 2004 electric rate order.

See Note 4 - Regulatory Matters.

2004 annual report 35

The EPA has initiated enforcement actions against several major electric utilities citing violations of the Clean Air Act, asserting that older, coal-fired power plants have been modified in ways that would require them to comply with the more restrictive "new source" provisions of the Clean Air Act. Detroit Edison received and responded to information requests from the EPA on this subject. The EPA has not initiated proceedings against Detroit Edison. The United States District Court for the Southern District of Ohio Eastern Division issued a decision in August 2003 finding Ohio Edison Company in violation of the new source provisions of the Clean Air Act. If the Court's decision is upheld, the electric utility industry could be required to invest substantial amounts on pollution control equipment. During the same month, however, a district court in a different division rendered a conflicting decision on the matter. On October 27, 2003, the EPA promulgated new rules, effective December 26, 2003, allowing repair, replacement or upgrade of 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 will be considered routine maintenance, however any changes in emissions would be subject to existing pollution permit limits and other state and federal programs for pollutants. Several states and environmental organizations have challenged these regulations and, on December 24, 2003, were granted a stay until the U.S. Court of Appeals D.C. Circuit hears the arguments on the case. We cannot predict the future impact of this issue upon Detroit Edison.

Water - In July 2004, the EPA published final regulations establishing performance standards for reducing fish loss at existing power plant cooling water intake structures. These regulations require individual facility studies, and possible intake modifications that will be determined and implemented over the next five to seven years. It is estimated that we will incur up to

$50 million in additional capital expenditures for Detroit Edison.

Contaminated Sites - DTE Enterprises Inc. (MichCon and Citizens) owns, or previously owned, 18 former manufactured gas plant (MGP) sites. During the mid-1980's, Enterprises conducted preliminary environmental investigations at former MGP sites, and some contamination related to the by-products of gas manufacturing was discovered at each site. Enterprises employed outside consultants to evaluate remediation alternatives and associated costs for these sites. As a result of these studies, Enterprises accrued a liability and a corresponding regulatory asset of $24 million. At December 31, 2004, the reserve balance was $24 million of which $4.5 million was classified as current.

Our current estimates indicate that the previously accrued amounts are adequate to cover the costs of required remedial actions.

Detroit Edison conducted remedial investigations at contaminated sites, including two former MGP sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is approximately $8 million, which is expected to be incurred over the next several years. As a result of the investigation, Detroit Edison accrued approximately $8 million liability during 2004.

DTE ENERGY OPERATING SYSTEM AND DTE2 During 2002, we adopted the DTE Energy Operating System, which is the application of tools and operating practices that have resulted in operating efficiencies, inventory reductions and improvements in technology systems, among other enhancements.

Operation and maintenance expenses benefited from our Company-wide initiative to pursue cost efficiencies and enhance operating performance. We expect continued cost containment efforts and process improvements.

In 2003, we began the implementation of DTE2, a Company-wide initiative to improve existing processes and to implement new core information systems including, finance, human resources, supply chain and work management. We expect to incrementally spend approximately $150 million to $175 million over the life of the project. We expect the benefits to outweigh this investment primarily from lower costs, faster business cycles, repeatable and optimized processes, enhanced internal controls, improvements in inventory management and reductions in system support costs.

We are in process of launching the first phase of our multi-year DTE2 project. Although our implementation plan includes detailed testing and contingency arrangements to ensure a smooth and successful transition, wve can provide no assurance that complications will not arise that could interrupt our operations.

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

FAIR VALUE OF CONTRACTS The following disclosures are voluntary and we believe provide enhanced transparency of the derivative activities and position of our Energy Trading & Marketing segment and our other businesses.

We use the criteria in Statement of Financial Accounting Standards No. 133, 'AccountingforDerivative Instruments and Hedging Activities," as amended and interpreted, to determine if certain contracts must be accounted for as derivative instruments.

The rules for determining whether a contract meets the criteria for derivative accounting are numerous and complex. Moreover, significant judgment is required to determine whether a contract requires derivative accounting, and similar contracts can some-times be accounted for differently. If a contract is accounted for as a derivative instrument, it is recorded in the financial statements as Assets or Liabilities from Risk Management and Trading Activity, at the fair value of the contract. The recorded fair value of the contract is then adjusted quarterly to reflect any change in the fair value of the contract, a practice known as mark-to-market (MTM) accounting.

Fair value represents the amount at which willing parties would transact an arms-length transaction. To determine the fair value of contracts that are accounted for as derivative instruments, we use a combination of quoted market prices and mathematical valu-ation models. Valuation models require various inputs, including forward prices, volatility, interest rates, and exercise periods.

Contracts we typically classify as derivative instruments are power and gas forwards, futures, options and swaps, as well as foreign currency contracts. Items we do not generally account for as h

36 2004 annual report 11

derivatives (and which are therefore excluded from the following tables) include gas inventory, gas storage and transportation arrangements, full-requirements power contracts and gas and oil reserves. As subsequently discussed, we have fully reserved the value of derivative contracts beyond the liquid trading timeframe and which therefore do not impact income.

The subsequent tables contain the following four categories represented by their operating characteristics and key risks.

"Proprietary Trading" represents derivative activity transacted with the intent of taking a view, capturing market price changes, or putting capital at risk. This activity is speculative in nature as opposed to hedging an existing exposure.

"Structured Contracts" represents derivative activity transacted with the intent to capture profits by originating substantially hedged positions with wholesale energy marketers, utilities, retail aggregators and alternative energy suppliers. Although transactions are generally executed with a buyer and seller simultaneously, some positions remain open until a suitable offsetting transaction can be executed.

'Economic Hedges" represents derivative activity associated with assets owned and contracted by DTE Energy, including forward sales of gas production and trades associated with owned transportation and storage capacity. Changes in the value of derivatives in this category economically offset changes in the value of underlying non-derivative positions, which do not qualify for fair value accounting. The difference in accounting treatment of derivatives in this category and the underlying non-derivative positions can result in significant earnings volatility as discussed in more detail in the preceding Results of Operations section.

"Gas Production" represents derivative activity associated with our Michigan gas reserves. A substantial portion of the price risk associated with these reserves has been mitigated through 2013. Changes in the value of the hedges are recorded as Liabilities from Risk Management and Trading with an offset in other comprehensive income to the extent that the hedges are deemed effective. The amounts shown in the following tables exclude the value of the underlying gas reserves and the changes therein.

roll forward of mark to market energy contract net assets The following tables provide details on changes in our MTM net asset or (liability) position during 2004:

MTMatDecember31,2003 10 17

$ (171)

$ (144)

(81)

$ (225)

Reclassedto realized upon settlement (10)

(10) 89 69 42 111 Changesinfairvaluerecordedtoincome 5

12 (20)

(3)

(12)

(15)

Amortization of option premiums (2)

(2)

Amounts recorded to unrealized income (7) 2 69 64 30 94 Amounts recorded in OCI (Note 1) 4 4

(78)

(74)

Option premiums paid and other 4

4 29 33 MTM at December 31, 2004 3

23 (98)

(72)

$ (100)

$ (172)

The following table provides a current and noncurrent analysis of Assets and Liabilities from Risk Management and Trading Activities as reflected in the Consolidated Statement of Financial Position as of December 31, 2004. Amounts that relate to contracts that become due within twelve months are classified as current and all remaining amounts are classified as noncurrent.

Current assets 48 115

$ 150 (33) 280 16 296 Noncurrent assets 18 44 82 (19) 125 125 Total MTM assets 66 159 232 (52) 405 16 421 Current liabilities (45)

(98)

(204) 33 (314)

(55)

(369)

Noncurrent liabilities (18)

(38)

(126) 19 (163)

(61)

(224)

Total MTM liabilities (63)

(136)

(330) 52 (477)

(116)

(593)

Total MITM net assets (liabilities) 3 23 (98)

(72)

S (100)

$ (172) 2004 annual report 37

Maturity of Fair Value of MTM Energy Contract Net Assets As previously discussed, we fully reserve all unrealized gains and losses related to periods beyond the liquid trading timeframe.

Our intent is to recognize MITM activity only when pricing data is obtained from active quotes and published indexes.

Actively quoted and published indexes include exchange traded (i.e., NYNIEX) and over-the-counter (OTO) positions for which broker quotes are available. The NYMEX has currently quoted prices for the next 72 months. Although broker quotes for gas and power are generally available for 18 and 24 months into the future, respectively, we fully reserve all unrealized gains and losses related to periods beyond the liquid trading timeframe and which therefore do not impact income.

The table below shows the maturity of our MITM positions:

Source of Fair Value 2008 Total and Fair (in Millions) 2005 2006 2007 Beyond Value Proprietary Trading 3

$ (2) $ 2 3

Structured Contracts 17 4

1 1

23 Economic Hedges (55)

(27)

(16)

(98)

Total Energy Marketing

& Trading (35)

(25)

(13) 1 (72)

Other Non-Trading Activities (38)

(51)

(11)

(100)

Total

$ (73)

S (76)

$ (24)

$ 1

$(172)

Quantitative and Qualitative Disclosures About Market Risk Commodity Price Risk DTE Energy has commodity price risk arising from market price fluctuations in conjunction with the anticipated purchase of electricity to meet its obligations during periods of peak demand. Wte also are exposed to the risk of market price fluctuations on gas sale and purchase contracts, gas production and gas inventories. To limit our exposure to commodity price fluctuations, we have entered into a series of electricity and gas futures, forwards, option and swap contracts. Commodity price risk associated with our electric and gas utilities is limited due to the PSCR and GCR mechanisms (Note 1).

Our Energy Services and Biomass businesses are also subject to crude oil price risk. As previously discussed, the Section 29 tax credits generated by DTE Energys synfuel and biomass operations are subject to phase out if domestic crude oil prices reach certain levels.

See Note 12 - Financial and Other Derivative Instruments for further discussion.

Credit Risk Bankruptcies We purchase and sell electricity, gas, coal, coke and other energy products from and to numerous companies operating in the steel, automotive, energy, retail and other industries.

A number of customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We have negotiated or are currently involved in negotiations with each of the companies, or their successor companies, that have filed for bankruptcy protection. W'e regularly review contingent matters relating to purchase and sale contracts and record provisions for amounts considered at risk of probable loss.

Wre believe our accrued amounts are adequate for probable losses. The final resolution of these matters is not expected to have a material effect on our financial statements in the period they are resolved.

We engage in business with customers that are non-investment grade. We closely monitor the credit ratings of these customers and, when deemed necessary, we request collateral or guarantees from such customers to secure their obligations.

Energy Trading & CoEnergy Portfolio We utilize both external and internally generated credit assessments when determining the credit quality of our trading counterparties. The following table displays the credit quality of our trading counterparties as of December 31, 2004:

Credit Exposure before Cash Cash Net Credit (in Millions)

Collateral Collateral Exposure Investment Grade (1)

A-and Greater 234 (2) 232 BBB+ and BBB 191 (18) 173 BBB-17 17 Total Investment Grade 442 (20) 422 Non-investment grade (2) 15 15 Internally Rated

-investmentgrade13) 78 (1) 77 Internally Rated

- non-investment grade (4) 2 2

Total S

537 S (21)

$ 516 (11 This category includes counterparties with minimum credit ratings of Baa3 assigned by Moody's Investors Service (Moody's) and BBB-assigned by Standard & Poors Rating Group (Standard & Poors). The five largest counterparty exposures combined for this category represented 28% of the total gross credit exposure.

(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 2% of the total gross credit exposure.

(3) This category includes counterparties that have not been rated by Moody's or Standard & Poors, but are considered investment grade based on DTE Energy's evaluation of the counterparty's creditworthiness. The five largest counterparty exposures combined for this category represented 9% of the total gross credit exposure.

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

iI 38 2004 annual report it

Interest Rate Risk DTE Energy is subject to interest rate risk in connection with the issuance of debt and preferred securities. In order to manage interest costs, we use treasury locks and interest rate swap agreements. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR).

As of December 31, 2004, the Company has a floating rate debt to total debt ratio of approximately 11% (excluding securitized debt).

Foreign Currency Risk DTE Energy has foreign currency exchange risk arising from market price fluctuations associated with fixed priced contracts.

These contracts are denominated in Canadian dollars and are primarily for the purchase and sale of power as well as for long-term transportation capacity. To limit our exposure to foreign currency fluctuations, we have entered into a series of currency forward contracts through 2008.;

Summary of Sensitivity Analysis We performed a sensitivity analysis to calculate the fair values of our commodity contracts, long-term debt instruments and foreign currency forward contracts. The sensitivity analysis involved increasing and decreasing forward rates at December 31, 2004 by a hypothetical 10% and calculating the resulting change in the fair values of the commodity, debt and foreign currency agreements.

The results of the sensitivity analysis calculations follow:

Activity an Millions)

Assuming a 10%/6 Assuming a 10%

increase in rates decrease in rates Change in the fair value of Gas Contracts (18) 18 Commodity contracts Power Contracts 1

(2) Commodity contracts Oil Contracts 15 (8)

Commodity options Interest Rate Risk

$ (311) 325 Long-term debt Foreign Currency Risk $

Forward contracts report of management's responsibility:

for financial statements and internal control over financial reporting Financial Statements We have reviewed this annual report to shareholders, and based on our knowledge, this annual report does not contain any untrue' statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circum-stances under which such statements were made, not misleading with respect to the period covered by this annual report. Also, based on our knowledge, the financial statemeiits, and other finran-cial information included in this annual report, fairly present in all material respects the financial condition, results of opertions and cash flows of DTE Energy as of, and for, the periods presented.

Internal Control Over Financial Reporting The management of DTE Energy Company is responsible for establishing and maintaining adequate internal control over financial reporting. DTE Energy Company's internal control system was designed to provide reasonable assurance to the com-pany's management and board of directors regarding the prepara-tion and fair presentation of published financial statements.

AU internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems'determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of the effectiveness to future periods are subject to the risks that control may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

DTE Energy Company management' assessed the effectiveness of the company's internal control over financial reporting as of December 31, 2004. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. -Based on our assessment, management believes that, as of December 31, 2004, DTE Energy Company's internal control over financial reporting was effective based on those criteria.

Our management's assessment of the effectiveness of the company's internal control over financial reporting has been audited by DTE Energy's independent auditors, as stated in their report which is included herein.

Anthony F. Early Jr.

Chairman, Chief Executive and Chief Operating Officer David E. Meador Executive Vice President and Chief Financial Officer 2004 annual report 39

reports of independent registered public accounting firm To the Board of Directors and Shareholders of DTE Energy Company:

We have audited management's assessment, included in the accompanying Management's report on Internal Control Over Financial Reporting, that DTE Energy Company and subsidiaries (the "Company") maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Interal Control - Integrated Pramework issued by the Committee of Sponsoring Organizations of the Theadway Commission.

The Companrs management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management's assessment and an opinion on the effectiveness of the Companys internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A companys internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company, (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internul Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control - IntegratedFramework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of December 31, 2004 and for the year then ended; and our report dated March 15, 2005 expressed an unqualified opinion on those consolidated financial statements.

Detroit, Michigan March 15, 2005 Deloitte.

Deloitte & Touche LLP Suite 900, 600 Renaissance Center Detroit, Michigan 48243-1704 To the Board of Directors and Shareholders of DTE Energy Company.

We have audited the consolidated statement of financial position of DTE Energy Company and subsidiaries (the "Company") as of December 31,2004 and 2003, and the related consolidated statements of operations, cash flows, and changes in shareholders' equity and comprehensive income for each of the three years in the period ended December 31,2004. These financial statements are the responsibility of the Company's management Our responsibility is to express an opinion on the consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presenta-tion. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of DTE Energy Company and subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, in connec-tion with the required adoption of certain new accounting principles, in 2003 the Company changed its method of accounting for asset retirement obliga-tions, energy trading contracts and gas inventories and in 2002 the Company changed its method of accounting for goodwill and energy trading contracts.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31,2004, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 15,2005 expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control over financial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting, Detroit, Michigan March 15,2005 Deloitte.

Deloitte & Touche LLP Suite 900, 600 Renaissance Center Detroit, Michigan 48243-1704 40 2004 annual report 11

consolidated statement of operations Year Ended December 31 Operating Revenues 7,114 7,041 6,729 Operating Expenses Fuel, purchased power and gas 02,07 2,241 2,099 Operation and maintenance 3,420 3,109 2,589 Depreciation, depletion and amortization 744 687 737 Taxes other than income 312 334 352 Asset gains and losses, net (215)

(7)

(42) 6,268 6,294 5,735 Operating Income 846 747 994 Other (Income) and Deductions Interest expense 518 546 569 Interest income (55)

(37)

(29)

Other income (80)

(110)

(45)

Other expenses 67 82 34 450 481 529 Income Before Income Taxes and Minority Interest 396 266 465 Income Tax Provision (Benefit) (Note 7) 165 (123)

(84)

Minority Interest (212)

(91)

(37)

Income from Continuing Operations 443 480 586 Income (Loss) from Discontinued Operations, net of tax (Note 3)

(12) 68 46 Cumulative Effect of Accounting Changes, net of tax (Note 2)

(27)

Net Income 431 521 632 Basic Earnings per Common Share (Note 8)

Income from continuing operations 2.56 2.87 3.57 Discontinued operations

(.06)

.41

.28 Cumulative effect of accounting changes

(.17)

Total 2.50 3.11 3.85 Diluted Earnings per Common Share (Note 8)

Income from continuing operations 2.55 2.85 3.55 Discontinued operations

(.06)

.40

.28 Cumulative effect of accounting changes

(.16)

Total 2.49.

3.09 3.83 Average Common Shares Basic 173-168 164 Diluted 173 168 165 Dividends Declared per Common Share 2.06 2.06 2.06 See Notes to Consolidated Financial Statements 2004 annual report 41

consolidated statement of financial position December31 ASSETS Current Assets Cash and cash equivalents Restricted cash (Note 1)

Accounts receivable Customer (less allowance for doubtful accounts of $129 and $99, respectively)

Accrued unbilled revenues Other Inventories Fuel and gas Materials and supplies Assets from risk management and trading activities Other 56,-

126-,

880-378 383 54 131 877 316 338 0 :

509:

I D -:,

~159

- ' ;,..' 20

- -S :7 209 467 162 186 181 2,996 2,712 Investments Nuclear decommissioning trust funds

.590 518 Other 558 601 1,148 1,119

's!,

l Property Property, plant and equipment 18,011 17,679 Less accumulated depreciation and depletion (Note 2)

(7,520)

(7,355) 10,491 10,324 Other Assets Goodwill (Note 3) 2067 2,067 Regulatory assets (Note 4) 2.119 2,063 Securitized regulatory assets (Note 4) 1,438

-1,527 Notes receivable 529 469 Assets from risk management and trading activities 12,5 88 Prepaid pension assets 184 181 Other 200 203 6,662-6,598 Total Assets 21,297 20,753 I

See Notes to Consolidated Financial Statements 42 2004 annual report II

December31 LIABILITIES AND SHAREHOLDERS' EQUrlY Current Liabilities Accounts payable

-892' 625 Accrued interest S

K

- i 110 Dividends payable s

90 87 Accrued payroll V J' 33 51 Income taxes 16 185 Short-term borrowings 40V 370 Current portion long-term debt including capital leases 514 477 Liabilities from risk management and trading activities e

369 326 Other 581-593 3,009.

2,824 Other Liabilities f

Deferred income taxes 1.1 24 988 Regulatory liabilities (Notes 2 and 4)

L 817.

817 Asset retirement obligations (Note 2)

7.

916 866 Unamortized investmenttax credit I

143 156 Liabilities from risk management and trading activities L

w-224, 173 Liabilities from transportation and storage contracts 387 495 Accrued pension liability

'265 345 Deferred gains from asset sales 414 311 Minority interest 132 156 Nuclear decommissioning (Notes 2 and 5) 77 67 Other 635 599 5,134 4,973 Long-Term Debt (net of current portion) (Note 9)

Mortgage bonds, notes and other 5,673 5,624 Securitization bonds 1,400 1,496 Equity-linked securities 178-185 Trust preferred-linked securities i289' 289 Capital lease obligations 66 75 7.606 7,669 Commitments and Contingencies (Notes 4, 5 and 13)

Shareholders' Equity Common stock, without par value, 400,000,000 shares authorized, 174,209,034 and 168,606,522 shares issued and outstanding, respectively 3,323 3,109 Retained earnings Lt383 2,308 Accumulated other comprehensive loss

[158)

(130) 5,548 5,287 Total Liabilities and Shareholders' Equity S

21,297.

20,753 See Notes to Consolidated Financial Statements 2004 annual report 43

consolidated statement of cash flow Year Ended December 31 Operating Activities Net income 431 521 632 Adjustments to reconcile net income to net cash from operating activities:

Depreciation, depletion and amortization 744 691 759 Deferred income taxes 129 (220)

(208)

Gain on sale of interests in synfuel projects (219)

(83)

(40)

Gain on sale of ITC and other assets, net (17)

(145)

Partners' share of synfuel project losses (223)

/78)

(40)

Contributions from synfuel partners

.141 65 22 Cumulative effect of accounting changes 27 Changes in assets and liabilities, exclusive of changes shown separately (Note 1) 9 172 (129)

Net cash from operating activities 995 950 996 Investing Activities Plant and equipment expenditures - utility (815)

(679) 1794)

Plant and equipment expenditures - non-utility (89)

(72)

(190)

Investments in joint ventures (36)

(34)

(21)

Proceeds from sale of interests in synfuel projects 221 89 32 Proceeds from sale of ITC and other assets 104 669 9

Restricted cash for debt redemptions 5

106 (79)

Other investments (71)

(69)

(72)

Net cash from (used for) investing activities (681)'

10 (1,115)

Financing Activities Issuance of long-term debt

. 736 527 1,138 Redemption of long-term debt (759)

(1,208)

(793)

Short-term borrowings, net 33 (44)

(267)

Issuance of common stock 41 44 265 Dividends on common stock (354)

(346)

(338)

Other (9)

(12)

(21)

Net cash used for financing activities (312)

(1,039)

(16)

Net Increase (Decrease) in Cash and Cash Equivalents 2

(79)

(135)

Cash and Cash Equivalents at Beginning of Period 54 133 268 Cash and Cash Equivalents at End of Period 56 54 133 See Notes to Consolidated Financial Statements 44 2004 annual report 11

consolidated statement of changes in shareholders' equity and comprehensive income Balance,December31,2001 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)

Net change in unrealized losses on derivatives, net of tax (33)

(33)

Unearned stock compensation and other (28)

(3)

(31)

Balance, December 31, 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)

Pension obligations (Note 14) 420 420 Net change in unrealized losses on derivatives, net of tax 17 17 Net change in unrealized gains on investments, net of tax 52 52 Unearned stock compensation and other 1

3 4

Balance, December 31, 2003 168,607 3,109 2,308 (130) 5,287 Net income 431 431 Issuance of newshares klh5,671, 223

=-23 Dividends declared on common stock 1357)

-357)

Repurchase and retirement of common stock (69)

(3)

-3)

Pension obligations (Note 14) 7 7

Net change in unrealized losses on derivatives, net of tax (15)

(15)

Net change in unrealized losses on investments, net of tax (2)-

i (20)-

Unearned stock compensation and other (6) 1 (5)?

Balance, December 31, 2004 174,209.

3,323 2

383 -

( 158)

S '5548-The following table displays comprehensive income (loss):

Net income I$

c f431 521 632 Other comprehensive income (loss), net of tax:

Pension obligations, net of taxes of $(4), $(226) and $280 (Notes 4 and 14) 7 420 (518)

Net unrealized losses on derivatives:

Gains or (losses) arising during the period, net of taxes of $26, $(8) and $32 (49) 16 (60)

Amounts reclassified to earnings, net of taxes of $(18),$-and $15) 34 1

27 (15) 17 (33)

Net unrealized gains (losses) on investments:

Gains (losses) arising during the period, net of taxes of $3, $(28) and $-

(5) 52 Amounts reclassified to earnings, net of taxes of $8, $- and $-

(15)

(20) 52 Comprehensive Income 403 !$

-1,010 81 i See Notes to Consolidated Financial Statements 2004 annual report 45

notes to consolidated financial statements NOTE-1 SIGNIFICANT ACCOUNTING POLICIES Corporate Structure DTE Energy is an exempt holding company under the Public Utility Holding Company Act of 1935 and owns the following businesses:

'7

The Detroit Edison Company (Detroit Edison), an electric utility engaged in the generation, purchase, distribution and sale of electric energy to 2.1 million customers in southeast Michigan;

Michigan Consolidated Gas Company (MlichCon), a natural gas utility 9 W engaged in the purchase, storage, transmission and distribution and sale of natural gas to 1.2 million customers throughout Michigan; and

Other non-utility subsidiaries engaged in energy marketing and trading, energy services and various other electricity, coal and gas related businesses.

Detroit Edison and MichCon are regulated by the Michigan Public 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 Energy. In addition, we are regulated by other federal and state regulatory agencies including the Nuclear Regulatory Commission (NRC) and the Environmental Protection Agency, among others.

Segments realigned - Through 2004, we operated our businesses through three strategic business units (Energy Resources, Energy Distribution and Energy Gas). Each business unit had utility and non-utility operations. The balance of our business consisted of Corporate & Other. See Note 16 for further discussion. In 2005, wve expect to realign our business units to strengthen the Company's focus on customer relationships and growth within our non-utility businesses. Based on this structure, wve will set strategic goals, allocate resources and evaluate performance. Beginning with the first quarter of 2005, we expect to report our segment information based on the following realignment:

Electric Utility, consisting of Detroit Edison;

Gas Utiliti primarily consisting of MichCon;

Non-utility Operations

Power and Industrial Projects, primarily consisting of synfuel projects, on-site energy services, steel-related projects, power generation with services, and waste coal recovery operations;

Unconventional Gas Production, primarily consisting of gas production and coal bed methane operations; 46 2004 annual report

Fuel Pansportation and Marketing, primarily consisting of coal transportation and marketing, gas pipelines and storage, and energy marketing and trading operations; and Corporate & Other, primarily consisting of corporate support functions and certain energy technology investments.

References in this report to "we," "us," "our" or "Company" are to DTE Energy and its subsidiaries, collectively.

Principles of Consolidation WVe consolidate all majority owned subsidiaries and investments in entities in which we have controlling influence. Non-majority owned investments are accounted for using the equity method when the company is able to influence the operating policies of the investee. Non-majority owned investments include investments in limited liability companies, partnerships or joint ventures.

When we do not influence the operating policies of an investee, the cost method is used. We eliminate all intercompany balances and transactions.

For entities that are considered variable interest entities, wve apply the provisions of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46-R, "Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51."

For a detailed discussion of FIN 46-R, see Note 2 - New Accounting Pronouncements.

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

Prior to December 2004, DTE Energy did not eliminate amounts, principally within Other Income and Other Deductions, resulting from certain intercompany transactions. The amounts of the transactions are immaterial and had no effect on net income.

Previously reported prior period amounts have been adjusted to eliminate those intercompany transactions and are now consistent with the current year's presentation. We reclassified certain other prior year balances to match the current year's financial state-ment presentation.

Revenues Revenues from the sale and delivery of electricity, and the sale, delivery and storage of natural gas are recognized as services are provided. Detroit Edison and MichCon record revenues for electric and gas provided but unbilled at the end of each month.

Detroit Edison's accrued revenues include a component for the cost of power sold that is recoverable through the Power Supply Cost Recovery (PSCR) mechanism. MichCon's accrued revenues include a component for the cost of gas sold that is recoverable 11

through the Gas Cost Recovery (GCR) mechanism. Annual PSCR and GCR proceedings before the MIPSC permit Detroit Edison and MlichCon to recover prudent and reasonable supply costs. Any overcollection or undercollection of costs, including interest, will be reflected in future rates. Prior to 2004, Detroit Edison's retail rates were frozen under Public Act (PA) 141. See Note 4 for further discussion. Accordingly, Detroit Edison did not accrue revenues under the PSCR mechanism prior to 2004.

Non-utility businesses recognize revenues as services are provided and products are delivered. Our Energy Mlarketing & Trading seg-ment records in revenues net unrealized derivative gains and losses on energy trading contracts, including those to be physically settled.

Gains from Sale of Interests in Synthetic Fuel Facilities Through December 2004, we have sold majority interests in eight of our nine synthetic fuel production plants, representing approxi-mately 92% of our total production capacity. Proceeds from the sales are contingent upon production levels and the value of Section 29 tax credits. Section 29 tax credits are subject to phase out if domestic crude oil prices reach certain levels. See Note 13 for further discussion. We recognize gains from the sale of interests in the synfuel facilities as synfuel is produced and sold, and when there is persuasive evidence that the sales proceeds have become fixed or determinable and collectibility is reasonably assured.

We have recorded gains from the sale of interests in synthetic fuel facilities totaling $219 million, $83 million and $40 million during 2004, 2003 and 2002, respectively.

Until the gain recognition criteria are met, gains from selling interests in synfuel facilities will be deferred. It is possible that gains will be deferred in the first, second and/or third quarters of each year until there is persuasive evidence that no tax credit phase out Nvill occur for the applicable calendar year. This could result in shifting earnings from earlier quarters to later quarters of a calendar year.

Comprehensive Income We comply with Statement of Financial Accounting Standards (SFAS) No. 130, "Reporting Comprehensive Income," that established standards for reporting comprehensive income.

SFAS No. 130 defines comprehensive income as the change in common shareholders' equity during a period from transactions and events from non-owner sources, including net income.

As shown in the following table, amounts recorded to other comprehensive income (OCI) at December 31, 2004 include:

unrealized gains and losses from derivatives accounted for as cash flow hedges under SFAS No. 133, 'Accounting for Derivative Instruments and Hedging Activities;" unrealized gains and losses on available for sale securities under SFAS No. 115, 'Accounting for Certain Investments in Debt and Equity Securities;" and, minimum pension liabilities as prescribed by SFAS No. 87, "Employers'Accountingfor Pensions."

Cash Equivalents and Restricted Cash Cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with remaining maturities of three months or less. Restricted cash consists of funds held to satisfy requirements of certain debt and partnership operating agreements. Restricted cash is classified as a current asset as all restricted cash is designated for interest and principal payments due within one year.

Inventories We value fuel inventory and materials and supplies at average cost.

Gas inventory at MichCon is determined using the last-in, first-out (LIFO) method. At December 31, 2004, the replacement cost of gas remaining in storage exceeded the $89 million LIFO cost by $330 mil-lion. At December 31, 2003, the replacement cost of gas remaining in storage exceeded the $117 million LIFO cost by $251 million. During 2004, AlichCon liquidated 5.7 billion cubic feet of prior years' LIFO lay-ers. The liquidation benefited 2004 cost of gas by approximately $7 mil-lion, but had no impact on earnings as a result of the GCR mechanism.

Our Energy Marketing & Trading segment uses the average cost method for its gas in inventory.

Property, Retirement and Maintenance, and Depreciation and Depletion Summary of property by classification as of December 31:

tin Millions) 2004 2003 Property, Plant and Equipment Electric Utility Generation Distribution Total Electric Utility Gas Utility Distribution Storage Other Total Gas Utility Energy Services Coal Based Fuels On-Site Energy Merchant Generation Other Total Energy Services Other Non-utility and Other Total Property, Plant and Equipment Less Accumulated Depreciation and Depletion Electric Utility Generation Distribution Total Electric Utility Gas Utility Distribution Storage Other Total Gas Utility Energy Services Coal Based Fuels On-Site Energy Merchant Generation Other Total Energy Services Other Non-utility and Other Total Accumulated Depreciation and Depletion Net Property, Plant and Equipment 7.100 '$

6,938 5,831 5,733 IZ

. 2931 '

12,671.

Z 2020*

,9

'221 224

- 883 855

3,124 3,040 X::., 6514 652

..193 180

174 229 8

13 1,026' 1,074 930.

894

-18.011' 17,679 i3; i

7) -(3,231)

(2,077)

(2,108)

.(5,354)

(5,339)

(845)

(798)

(100)

(102)

.-- (448)

(432) 5' (1,393)

(1.332)

(272)

(219)

(:-3i

55)

(42) t it, '

l t {8)

(20)

.,3

.:(2)

'(348)

(283)

(425)

(401)

'17,520)

(7,355) 10,491$

10,324 Minimum Pension Liability Net Net Unrealized Unrealized Losses on Gains on Accumulated Other Comprehensive (inMillions)

Adjustment Derivatives Investments

'Loss Beginning balance $

(98)

$ 1851 53 (130)

Current-period change 7

(15)

(20)

(28)

Ending balance (91)

$ (1l)

$ 33 (158) 2004 annual report 47

Property is stated at cost and includes construction-related labor, materials, overheads and an "allowance for funds used during construction" (AFUDC). The cost of properties retired, less salvage, at Detroit Edison and MichCon are charged to accumulated depreciation.

Expenditures for maintenance and repairs are charged to expense when incurred, except for Fermi 2. Approximately $3.8 million of expenses related to the anticipated Fermi 2 refueling outage scheduled for 2006 were accrued at December 31, 2004. Amounts are being accrued on a pro-rata basis over an 18-month period that began in November 2004. Wse have utilized the accrue-in-advance policy for nuclear refueling outage costs since the Fermi 2 plant was placed in service in 1988. This method also matches the regulatory recovery of these costs in rates set by the AIPSC.

We base depreciation provisions for utility property at Detroit Edison and MichCon on straight-line and units of production rates approved by the MPSC. The composite depreciation rate for Detroit Edison was 3.4% in 2004, 2003 and 2002.

The composite depreciation rate for MfichCon was 3.6%, 3.5%,

and 3.6% in 2004, 2003 and 2002, respectively.

The average estimated useful life for each class of utility property, plant and equipment as of December 31, 2004 follows:

Estimated Useful lives in Years Utility Generation Distribution_ Transmission-_

Electric 39 37 Gas N/A 26 28 Non-utility property is depreciated over its estimated useful life using straight-line, declining-balance or units-of-production methods.

We credit depreciation, depletion and amortization expense when we establish regulatory assets for stranded costs related to the electric Customer Choice program and deferred environmental expenditures.

Gas Production We follow the successful efforts method of accounting for investments in gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves.

If an exploratory well has not found proved reserves, the costs of drilling the well are expensed. The costs of development wells are capitalized, whether productive or nonproductive.

Geological and geophysical costs on exploratory prospects and the costs of carrying and retaining unproved properties are expensed as incurred. An impairment loss is recorded to the extent that capitalized costs of unproved properties, on a property-by-property basis, are considered not to be realizable.

An impairment loss is recorded if the net capitalized costs of proved gas properties exceed the aggregate related undiscounted future net revenues. Depreciation, depletion and amortization of proved gas properties are determined using the units-of-production method.

Long-Lived Assets Our long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable. If the carrying amount of the asset exceeds the expected future cash flows generated by the asset, an impairment loss is recognized resulting in the asset being written down to its estimated fair value. Assets to be disposed of are reported at the lower of the carrying amount or fair value less cost to sell.

Intangible Assets, Including Software Costs Our intangible assets consist primarily of software. W'e capitalize the costs associated with computer software we develop or obtain for use in our business. We amortize intangible assets on a straight-line basis over expected periods of benefit.

Intangible assets amortization expense was $43 million in 2004,

$40 million in 2003 and $46 million in 2002. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2004 were $445 million and $151 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2003 were

$537 million and $303 million, respectively. Amortization expense of intangible assets is estimated to be $40 million annually for 2005 through 2009.

Excise and Sales Taxes We record the billing of excise and sales taxes as receivable with an offsetting payable to the applicable taxing authority, with no impact on the consolidated statement of operations.

Deferred Debt Costs The costs related to the issuance of long-term debt are deferred and amortized over the life of each debt issue. In accordance with MPSC regulations applicable to our electric and gas utilities, the unamortized discount, premium and expense related to debt redeemed with a refinancing are amortized over the life of the replacement issue. Discount, premium and expense on early redemptions of debt associated with non-utility operations are charged to earnings.

Insured and Uninsured Risks We have a comprehensive insurance program in place to provide coverage for various types of risks. Our insurance policies cover risk of loss from various events, including property damage, general liability, workers' compensation, auto liability and directors' and officers' liability.

Under our risk management policy, we self-insure portions of certain risks up to specified limits, depending on the type of exposure. We periodically review our insurance coverage. During 2003, 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 include an actuarially determined estimate of "incurred but not reported" (IBNR) claims. We have an actuarially determined estimate of our IBNR liability prepared annually and adjust the related reserve as appropriate.

48 2004 annual report 11

Stock-Based Compensation We have a stock-based employee compensation plan, which is described in Note 15. The plan permits the awarding of various stock awards, including options, restricted stock and performance shares. We account for stock awards under the plan under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, "Accountingfor Stock Issued to Employees." No compensation cost related to stock options is reflected in earnings, as all options granted had an exercise price equal to the market value of the underlying common stock on the date of grant. The recognition provisions under SFAS No. 123, "Accountingfor Stock-Based Compensation," require the recording of compensation expense for stock options equal to their fair value at date of grant as determined using an option pricing model. The following table illustrates the effect on net income and earnings per share if we had recorded compensation expense for options granted under the fair value recognition provisions of SFAS No. 123.

kn Milionst except pershare amounts)

-2004 2003 2002 Net Income As Reported 431 $

521 $

632 Less: Total Stock-based Expense (1)

(6)

(7)

Pro Faorma Net Income S '425 $

514 $

625 Income Per Share Basic - as reported

.$.Z50 $

3.11 $

3.85 Basic - pro forma US :.2.46 $

3.06 $

3.81 Diluted - as reported S

2.49 S 3.09 $

3.83 Diluted - pro forma S

2.45 $

3.05 $

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

Investments in Debt and Equity Securities We generally classify investments in debt and equity securities as either trading or available-for-sale and have recorded such investments at market value with unrealized gains or losses included in earnings or in other comprehensive income or loss, respectively. Changes in the fair value of nuclear decommissioning-related investments are recorded as adjustments to regulatory assets or liabilities (Note 5).

Investment in Plug Power In 1997, we invested in Plug Power Inc., a company that designs and develops on-site electric fuel cell power generation systems.

Since Plug Power is considered a development stage company, generally accepted accounting principles required us to record gains and losses from Plug Power stock issuances as an adjustment to equity. Prior to November 2003, we accounted for our investment in Plug Power under the equity method of accounting. We did not participate in Plug Power's secondary stock offering in November 2003 and as of December 31, 2003 we owned 14.1 million shares or approximately 19% of Plug Power's common stock. We have determined that we do not have the ability to exercise significant influence over the operating or financial policies of Plug Power.

Accordingly, we began prospective application of the cost method of accounting for our investment in Plug Power, effective November 2003. We record our investment at market value and account for unrealized gains and losses in other comprehensive income or loss.

In May 2004, we sold 3.5 million shares of Plug Power stock and recorded a gain of approximately $14 million, net of taxes. The sale reduced our ownership interest in Plug Power to 10.6 million shares, or approximately 14%.

Consolidated Statement of Cash Flows A detailed analysis of the changes in assets and liabilities that are reported in the consolidated statement of cash flows follows:

(in Milrions)

Changes in Assets and Liabilities, Exclusive of Changes Shown Separately Accounts receivable, net Accrued unbilled receivable Accrued GCR revenue Inventories Accrued/Prepaid Pensions Accounts payable Accrued PSCR refund Exchange gas payable Income taxes payable General taxes Risk management and trading activities Postretirement obligation Other 2004 2003 2002 73 $

(62)

(35)

(40) 88 266 112 (43)

(170)

(14)

.(64) 299 (131)

(50) S (20) 29 (61)

(196)

(21) 90 135 (12)

(129)

(54)

(5)

(71)

(1 0) 66 9

(8)

(36) 127 112 39 69 77 (37)

R S 9$

172 $

(129)

Supplementary cash and non-cash information for the years ended December31 were as follows:

ran Miflions) 2004 2003 2002 Cash Paid For Interest (excluding interest capitalized)

$ - 517 $

552 $

551 Income taxes 203 $

31 $

167 Noncash Investing and Financing Activities Notes received from sale of synfuel projects t $

214 $

238 $

217 Common stock contributed to pension plan 170 $

Exchange of debt 100 $

Issuance of equity-linked securities 21 See the following notes for other accounting policies impacting our financial statements:

Note Title 2

New Accounting Pronouncements 4

Regulatory Matters 7

Income Taxes 12 Financial and Other Derivative Instruments 14 Retirement Benefits and Trusteed Assets NOTE-2 NEW ACCOUNTING PRONOUNCEMENTS Energy Trading Activities Under Emerging Issues Task Force (EITF) Issue No. 98-10, "Accountingfor Contracts Involved in Energy Trading and Risk Management Activities," companies were required to use mark-to-market accounting for contracts utilized in energy trading activities. EITF Issue No. 98-10 was rescinded in October 2002, and energy trading contracts must now be reviewed to determine if they meet the definition of a derivative under SFAS No. 133,

'A ccountingfor Derivative Instruments and Hedging Activities."

SFAS No. 133 requires all derivatives to be recognized in the state-ment of financial position as either assets or liabilities measured at their fair value. SFAS No. 133 also requires that changes in the fair 2004 annual report 49

value of derivatives be recognized in earnings unless specific hedge accounting criteria are met. Energy trading contracts not meeting the definition of a derivative are accounted for under settlement accounting, effective October 25, 2002 for new contracts and effective January 1, 2003 for existing contracts.

Derivative contracts are only marked to market to the extent that markets are considered highly liquid where objective, transparent prices can be obtained. Unrealized gains and losses are fully reserved for transactions that do not meet this criteria.

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

Effective January 1, 2003, we no longer applied EITF Issue No. 98-10 to energy contracts and ARB No. 43 to gas inventory.

As a result of discontinuing the application of these accounting principles, we recorded a cumulative effect of accounting change that reduced net income for the first quarter of 2003 by $16 million (net of taxes of $9 million).

Asset Retirement Obligations On January 1, 201)3, we adopted SFAS No. 143, 'Accountingfor Asset Retirement Obligations," which requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred. We identified a legal retirement obligation for the decommissioning costs for our Fermi 1 and 2 nuclear plants.

To a lesser extent, we have retirement obligations for our synthetic fuel operations, gas production facilities, asphalt plant, gas gathering facilities and various other operations. As to utility operations, we believe that adoption of SFAS No. 143 results primarily in timing differences in the recognition of legal asset retirement costs that we are currently recovering in rates and are deferring such differences under SFAS No. 71, "Accounting for the Effects of Certain Tpes of Regulation."

As a result of adopting SFAS No. 143 on January 1,2003, we recorded a plant asset of $306 million with offsetting accumulated deprecia-tion of $106 million, a retirement obligation liability of $815 million and reversed previously recognized obligations of $377 million, principally nuclear decommissioning liabilities. We also recorded a cumulative effect amount related to utility operations as a regulatory asset of $221 million, and a cumulative effect charge against earnings of $11 million (net of tax of $7 million) for 2003.

If a reasonable estimate of fair value cannot be made in the period the asset retirement obligation is incurred, such as assets with an indeterminate life, the liability is to be recognized when a reason-able estimate of fair value can be made. Generally, distribution assets have an indeterminate life, retirement cash flows cannot be determined and there is a low probability of retirement, therefore no liability has been recorded for these assets.

The pro forma effect on earnings had SFAS No. 143 been adopted for all periods presented would decrease reported net income and basic and diluted earnings per share as follows:

(in Millions)

Net Basic and Diluted Year Income Earnings per Share 2002 4.8

.03 50 2004 annual report A reconciliation of the asset retirement obligation for 2004 follows:

(in MiWAons)

Asset retirement obligations atJanuary 1, 2004 866 Accretion 57 Liabilities settled (5)

Revisions in estimated cash flows (2)1 Asset retirement obligations at December 31, 2004 916 A significant portion of the asset retirement obligations represents nuclear decommissioning liabilities, which are funded through a surcharge to electric customers over the life of the Fermi 2 nuclear plant.

SFAS No. 143 also requires the quantification of the estimated cost of removal obligations, arising from other than legal obligations, which have been accrued through depreciation charges. At December 31, 2003, we reclassified approximately

$655 million of previously accrued asset removal costs related to our utility operations, which had been previously netted against accumulated depreciation to regulatory liabilities. There is a generic case before the MPSC to determine the accounting and regulatory treatment of removal costs for Michigan utilities.

Consolidation of Variable Interest Entities In January 2003, FASB Interpretation No. (FIN) 46, "Consolidation of Variable Interest Entities, an Interpretation ofAccounting Research Bulletin (ARB) No. 51, "was issued and requires an investor with a majority of the variable interests (primary beneficiary) in a variable interest entity to consolidate the assets, liabilities and results of operations of the entity.

A variable interest entity is an entity in which the equity investors do not have controlling interests, the equity investment at risk is insufficient to finance the entity's activities without receiving additional subordinated financial support from other parties, or equity investors do not share proportionally in gains or losses.

In October 2003 and December 2003, the FASB issued Staff Position No. FIN 46-6 and FIN 46-Revised (FIN 46-R), respectively, which clarified and replaced FIN 46 and also provided for the deferral of the effective date of FIN 46 for certain variable interest entities.

We have evaluated all of our equity and non-equity interests and have adopted all current provisions of FIN 46-R. The adoption of FIN 46-R did not have a material effect on our financial statements.

Medicare Act Accounting In December 2003, the "Medicare Prescription Drug, Improvement and Modernization Act of 2003" (Medicare Act) was signed into law. The Medicare Act provides for a non-taxable federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least "actuarially equivalent" to the benefit established by law. We elected at that time to defer the provisions of the Medicare Act, and its impact on our accumulated postretirement benefit obligation and net periodic postretirement benefit cost, pending the issuance of specific authoritative accounting guidance by the FASB.

In May 2004, FASB Staff Position (FSP) No. 106-2 was issued on accounting for the effects of the Medicare Act. The guidance in this FSP is applicable to sponsors of single-employer defined benefit postretirement health care plans for which (a) the employer has concluded the prescription drug benefits available under the plan to some or all participants are "actuarially equivalent" to Medicare Part D and thus qualify for the subsidy 11

under the Medicare Act and (b) the expected subsidy will offset or reduce the employer's share of the cost of the underlying postretirement prescription drug coverage on which the subsidy is based. Woe believe we qualify for the subsidy under the Medicare Act and the expected subsidy will partially offset our share of the cost of postretirement prescription drug coverage.

In June 2004, we adopted FSP No. 106-2, retroactive to January 1, 2004. As a result of the adoption, our accumulated postretirement benefit obligation for the subsidy related to benefits attributed to past service was reduced by approximately $95 million and was accounted for as an actuarial gain. The effects of the subsidy reduced net postretirement costs by $16 million in 2004.

Stock Based Payments In December 2004, the FASB issued SFAS No. 123-R, "Stock Based Payments, °which establishes the accounting for transactions in which an entity exchanges equity instruments for goods or services. Application of SPAS No. 123-R is required for interim or annual periods beginning after June 16, 2005 with earlier adoption encouraged. We have completed a preliminary review and estimate that the new standard will reduce reported earnings by approximately $5 million to $10 million per year.

Goodwill and Other Intangible Assets Effective January 1, 2002, we adopted SFAS No. 142, 'Goodwill and Other IntangibleAssets,"which addresses the financial accounting and reporting standards for the acquisition of intangible assets out-side of a business combination and for goodwill and other intangible assets subsequent to their acquisition. This accounting standard requires that goodwill no longer be amortized, but reviewed at least annually for impairment. In accordance with SFAS No. 142, we discontinued the amortization of goodwill effective January 1,2002.

NOTE-3 DISPOSITIONS International Transmission Company -

Discontinued Operation In February 2003, we sold International Transmission Company (ITC), our electric transmission business, for $610 million to affiliates of Kohlberg Kravis Roberts & Co. and Timaran Capital Partners, LLC. The sale generated a preliminary net of tax gain of $63 million in 2003. The gain was net of transaction costs, the portion of the gain that was refundable to customers and the write off of approximately $44 million of allocated goodwill. The gain was lowered to $58 million in 2004 under the MPSC's November 2004 final rate order that resulted in a revision of the applicable transaction costs and customer refund.

As prescribed by SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets, 'we have reported the operations of ITC as a discontinued operation as shown in the following table:

(in Millions) 2003 (3) 2002 Revenues (1) 21

$ 138 Expenses (2) 13

67 Operating income 8.

71 Income taxes 3

25 Income from discontinued operations 5

46 (1) Includes intercompany revenues of$18 million for2003 and $118 million for 2002 (2) Excludes general corporate overhead costs that were previously allocated to ITC in 2003 and 200Z (3) Represents activity from January 1, 2003 through February 28, 2003, when ITC was sold.

Detroit Edison's Steam Heating Business In January 2003, we sold Detroit Edison's steam heating business to Thermal Ventures II, LP. Due to the continuing involvement of Detroit Edison in the steam heating business, including the commitment to purchase steam and/or electricity through 2024, fund certain capital improvements and guarantee the buyer's credit facility, we recorded a net of tax loss of approximately $14 million in 2003. As a result of Detroit Edison's continuing involvement, this transaction is not considered a sale for accounting purposes.

The steam heating business had assets of $6 million at December 31,2002, and had net losses of $12 million in 2002.

See Note 13 - Commitments and Contingencies.

Southern Missouri Gas Company-Discontinued Operation We own Southern Missouri Gas Company (SMIGC), a public utility engaged in the distribution, transmission and sale of natural gas in southern Missouri. In the first quarter of 2004, management approved the marketing of SMGC for sale. As of March 31,2004, SMGC met the SFAS No. 144 criteria of an asset "held for sale," and we have reported its operating results as a discontinued operation. We recognized a net of tax impairment loss of approximately $7 million in 2004, representing the write-down to fair value of the assets of SMGC, less costs to sell, and the write-off of allocated goodwill. In November 2004, we entered into a definitive agreement providing for the sale of SMGC. Following receipt of regulatory approvals and resolution of other contingencies, it is anticipated that the transaction will close in 2005. SMGC had assets of $9 million and liabilities of

$35 million at December 31, 2004.

NOTE-4 REGULATORY MATTERS Regulation Detroit Edison and MichCon are subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to retail rates, recovery of certain costs, including the costs of generating facilities and regulatory assets, conditions of service, accounting and operating-related matters. Detroit Edison is also regulated by the FERC with respect to financing authorization and wholesale electric activities.

As subsequently discussed in the "Electric Industry Restructuring" section, Detroit Edison's rates were frozen through 2003 and capped for small business customers through 2004 and for residential customers through 2005 as a result of Public Act (PA) 141. However, Detroit Edison was allowed to defer certain costs to be recovered once rates could be increased, including costs incurred as a result of changes in taxes, laws and other governmental actions.

Regulatory Assets and Liabilities Detroit Edison and MichCon apply the provisions of SFAS No. 71,

'A ccoun tingfor the Effects of Certa in ltp es of Regulation, "

to their regulated operations.. SFAS No. 71 requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as revenue and expense in non-regulated businesses. Continued applicability of SFAS No. 71 requires that rates be designed to recover specific costs of providing regulated services and be charged to and collected from customers. Future regulatory changes or changes in the competitive environment could result in the Company discontinuing the application of SFAS No. 71 for some or all of its utility businesses and may require the write-off of the portion of any regulatory asset or liability that 2004 annual report 51

was no longer probable of recovery through regulated rates.

Management believes that currently available facts support the continued application of SFAS No. 71 to Detroit Edison and MichCon.

The following are balances and a brief description of the regulatory assets and liabilities at December 31:

fin Millions) 2004 2003 Assets Securitized regulatory assets

$ 1,438

$ 1,527 Recoverable income taxes related to securitized regulatory assets 788 837 Recoverable minimum pension liability 605 585 Asset retirement obligation 183 192 Other recoverable income taxes 109 114 Recoverable costs under PA 141 Net stranded costs 122 68 Excess capital expenditures 7

Deferred Clean Air Act expenditures 76 54 Midwest Independent System Operator charges 27 21 Transmission integration costs 10 Electric Customer Choice implementation costs 95 84 Enhanced security costs 8

6 Unamortized loss on reacquired debt 63 60 Deferred environmental costs 31 29 Accrued GCR revenue 55 19 Other 5

3 2174 2,082 Less amount included in current assets (55)

(19)

$ 2,119

$2,063 Liabilities Asset removal costs

$ 679 655 Excess securitization savings 14 Customer refund -1997 storm 2

2 Refundable income taxes 135 146 Accrued GCR potential disallowance 28 26 Accrued PSCR refund 112 Other

-3 3

959 846 Less amount included in current liabilities (142)-

(29)

$ 817 817 accounting principles due to the current under funded status of certain pension plans. The traditional rate setting process allows for the recovery of pension costs as measured by generally accepted accounting principles. Accordingly, the minimum pension liability associated with utility operations is recoverable.

See Notes 4 and 14.

Asset retirement obligation - Asset retirement obligations were recorded pursuant to adoption of SFAS No. 143 in 2003. These obligations are primarily for Fermi 2 decommissioning costs that are recovered in rates.

Other recoverable income taxes - Income taxes receivable from Detroit Edison's customers representing the difference in property-related deferred income taxes receivable and amounts previously reflected in Detroit Edison's rates.

Net stranded costs - PA 141 permits, after MPSC authorization, the recovery of and a return on fixed cost deficiency associated with the electric Customer Choice program. Net stranded costs occur when fixed cost related revenues do not cover the fixed cost revenue requirements.

Excess capital expenditures - Starting in 2004, PA 141 permits, after MPSC authorization, the recovery of and a return on capital expenditures that exceed a base level of depreciation expense.

Deferred CleanAirAct expenditures - PA 141 permits, after MPSC authorization, the recovery of and a return on Clean Air Act expenditures.

Midwest Independent System Operator charges - PA 141 permits, after MPSC authorization, the recovery of and a return on charges from a regional transmission operator such as the Midwest Independent System Operator.

Transmission integration costs - The MPSC's November 2004 final rate order denied recovery and determined these costs to be transaction expenses in DTE Energy's sale of ITC.

Electric Customer Choice implementation costs - PA 141 permits, after MPSC authorization, the recovery of and a return on costs incurred associated with the implementation of the electric Customer Choice program.

Enhanced security costs - PA 141 permits, after MPSC authorization, the recovery of enhanced homeland security costs for an electric generating facility.

Unamortized loss on reacquired debt - The unamortized discount, premium and expense related to debt redeemed with a refinancing are deferred, amortized and recovered over the life of the replacement issue.

Deferred environmental costs - The MPSC approved the deferral and recovery of investigation and remediation costs associated with former manufactured gas plant sites.

Accrued GCR revenue - Receivable for the temporary under-recovery of and a return on gas costs incurred by MichCon which are recoverable through the GCR mechanism.

LIABILITIES

Asset removal costs - The amount collected from customers for the funding of future asset removal activities.

Excess securitization savings - Savings associated with the 2001 securitization of Fermi 2 and other costs are refundable to Detroit Edison's customers.

ASSETS

Securitized regulatory assets - The net book balance of the Fermi 2 nuclear plant was written off in 1998 and an equivalent regulatory asset was established. In 2001, the Fermi 2 regulatory asset and certain other regulatory assets were securitized pursuant to PA 142 and an MPSC order. A non-bypassable securitization bond surcharge recovers the securitized regulatory asset over a fourteen-year period ending in 2015.

Recoverable income taxes related to securitized regulatory assets - Receivable for the recovery of income taxes to be paid on the non-bypassable securitization bond surcharge. A non-bypassable securitization tax surcharge recovers the income tax

Recoverable minimum pension liability -An additional minimum pension liability was recorded under generally accepted 52 2004 annual report 11

Customer refund - 1997storm - I storm costs, which will be refundei MPSC's November 2004 rate order.

Refundable income taxes - Income to MichCon's customers representi property-related deferred income t recognized pursuant to MPSC auth

Accrued GCR potential disallowar resulting from an MPSC order in M case that required MichCon to red, calculation of its 2002 GCR expens

Accrued PSCR refund - Payable fo over-recovery of and a return on pa beginning with the MPSC's Novemi transmission costs incurred by Det recoverable through the PSCR me(

Electric Rate Case Rate Request - In June 2003, Detroit I with the MPSC requesting a change ii resumption of the PSCR mechanism,.

costs. The application and subsequent request to increase base rates by $583 In addition, Detroit Edison requested assets. As subsequently discussed, Dc and final rate orders relating to its JA A summary of the rate orders follows

'he over collection of 1997 customers ($240 million) and electric Customer Choice customers I in accordance with the

($8 million). However, because of the rate caps under PA 141, not all of the increase was realized in 2004. The interim order also a taxes refundable terminated certain transition credits and authorized transition ng the difference in charges to electric Customer Choice customers designed to result axes payable and amounts in $30 million in additional revenues. Additionally, the MPSC orization.

authorized a reduced PSCR factor for all customers, designed to lower revenues by $126 million annually. However, the MIPSC order li c Pontial rfnd allowed Detroit Edison to increase base rates for customers still ichone s 2v00 Gn R plan subject to the cap in an equal and offsetting amount with the e

e required reduction in the PSCR factor to maintain the total

e.

capped rate levels currently in effect for these customers.

)r the temporary The MPSC deferred addressing other items in the rate request, ber 2004 rate order, including a surcharge to recover regulatory assets, until a final ber 204 rte oder;rate order was issued.

roit Edison which are chanism.

MPSCFinal Rate Order - On November 23, 2004, the MPSC issued an order for final rate relief. The MPSC determined that the base rate increase granted to Detroit Edison should be $336 million Edison filed an application annually effective November 24, 2004 and is applicable to all i retail electric rates, customers not subject to the rate cap. The final order provides md recovery of net stranded for the future recovery of losses resulting from electric Customer revisions resulted in a Choice. Additionally, beginning in 2005, the final order allows I million annually.

Detroit Edison to recover the discounts previously provided to recovery of certain regulatory special manufacturing contract (SMC) customers of $38 million, 4troit Edison received interim resulting in an overall base rate increase of $374 million annually.

ne 2003 rate application.

As subsequently discussed, Detroit Edison has been deferring certain costs as regulatory assets that it believes are recoverable Interim Rate Final Rate under PA 141 once rate caps expire. The final order addressed Increasell)

Increased )

numerous issues relating to regulatory assets, including the 248 336 amounts recoverable and the recovery mechanism. The final 38 order authorized the recovery of a lower level of stranded costs 248 374 than had been recorded through February 20, 2004, the date of (126)

(126) the interim order. Accordingly, Detroit Edison adjusted its net 122 248 stranded costs related regulatory asset, which decreased 2004 net income by $21 million.

Actual Estimate 2004 2005 (2) Total The MPSC's final order authorizes the recovery of approximately

$385 million of regulatory assets through three mechanisms:

$ 76

$ 68

$144

The first mechanism recovers certain accrued regulatory assets 27 49 76 over a five-year period using a regulatory asset recovery surcharge 7

15 22 (RARS) and is collectible from all full service customers as their (2)

(2) rate caps expire. The total amount to be collected is estimated 108 132 240 to be $240 million, plus carrying costs of 9.74% on unrecovered 95 6

101 balances. The recoverable regulatory assets include costs 44 44 iassociated with Clean Air Act compliance, deferred Midwest S 247

$ 138

$385 Independent System Operator (MISO) transmission fees, and deferred excess capital expenditures. The MPSC also authorized

,red in 2005, as well as carrying the refunding of over collected 1997 storm costs.

ithorized for recovery by the MPSC.

N in future MPSC proceedings, and

The second mechanism includes a surcharge to recover electric be reflected in future rates.

Customer Choice implementation costs of $101 million and is muary 20,2004, the MPSC collectible from both full service and electric Customer Choice

f. The order authorized customers. This charge will not be implemented until all ransition charge for current rate caps expire in 2006 and will include carrying bin t

Or -n costs of 7% on unrecovered balances.

(in Millions)

Base Rate Revenue Deficiency Recovery of SMC Discounts Overall Base Rate Increase PSCR Savings Total (in Millions)

Cumulative Recoverable RegulatoryAssets Clean Air Act MISO Transmission Costs Excess Capital Expenditures Customer Refund - 1997 Storm Electric Choice Implementation Costs Net Stranded Costs Total (1l The impact of rate caps not included.

(2)

Represents estimated amounts to be incur costs on unrecovered balances, that were au Actual amounts incurred are subject to revie any overcollections or undercollections will 1 MPSC Interim Rate Order - On Febi issued an order for interim rate relie:

an interim increase in base rates, a t customers participating in the electr program and a new PSCR factor.

The interim base rate increase totale(

effective February 21, 2004, and was a subject to a rate cap. The increase wa LtI VIAZUVIIUI %JALIIU~b d $248 million annually,

.pplicable to all customers not s allocated to both full-service

The third mechanism includes a surcharge to recover

$44 million in historical stranded costs incurred in 2002, 2003 and January and February 2004 and is collectible from electric Customer Choice customers, including carrying costs of 7% on unrecovered balances.

2004 annual report 53

Other significant items authorized by the MPSC in its final order

Rate increase was based on a 54% debt and 46% equity capital structure, and an 11% rate of return on common equity.

Customer rate caps do not expire until January 2006. As a result, the MPSC determined that there is a need to true-up stranded costs for at least 2004. This true-up case must be filed by March 31, 2005. The MPSC also permits Detroit Edison to file additional annual stranded cost true-up proceedings if it deems appropriate to do so pursuant to PA 141.

Transmission and MISO costs and costs associated with nitrogen oxide (NOx) allowances will be recoverable through the PSCR mechanism and charged to full service customers; however, costs associated with sulfur dioxide (SOx) allowances will not be included in the PSCR, but recoverable through base rates.

Full cost recovery of $550 million of Clean Air Act environmental expenditures was authorized. We believe that future mandated environmental expenditures will also be recovered through base rates.

A pension tracking mechanism was established to manage changes in pension costs. Under the tracking mechanism, Detroit Edison would recover or refund pension costs above or below the amount reflected in base rates. Detroit Edison was also required to propose a similar tracking mechanism for retiree health care costs. In February 2005, Detroit Edison filed a request with the MPSC seeking authority to implement a tracking mechanism for retiree health care costs (Other Postemployment Benefits Costs Tracker).

Detroit Edison was ordered to file a rate unbundling and restructuring case by March 23, 2005. As subsequently discussed, this rate restructuring proposal was ified on February 4,2005.

Changes to the existing electric Customer Choice program regarding customers returning to fall utility service. Customers electing to participate in the electric Customer Choice program will not be permitted to return to Detroit Edison's full service rates for two years. Electric Customer Choice customers return-ing to full service must remain on bundled rates for at least one year following their return. Customers who fail to give the appropriate notice or do not stay on the electric Customer Choice program for two years are required to pay the higher of the applicable tariff energy price plus 10%, or the market price of power plus 10%, for any power taken from Detroit Edison.

In December 2004, Detroit Edison and other parties filed petitions for rehearing relating to the MPSC's November 2004 final rate order. Among other items, Detroit Edison's petition requests a correction of the capital structure used in determination of the final order and recovery of certain disallowed costs. Detroit Edison awaits an MPSC decision on the petitions for rehearing.

Electric Rate Restructuring Proposal On February 4, 2005, Detroit Edison filed a rate restructuring proposal with the MPSC to restructure its electric rates and begin phasing out subsidies that are part of its current pricing structure.

The proposal would adjust rates for each customer class to be reflective of the full costs incurred to service such customers.

Under the proposal, commercial and industrial rates would be lowered, but residential rates would increase over a five-year period beginning in 2007. The MPSC anticipates that this proceeding will be completed in time to have new rates in effect no later than January 1,2006.

Other Postemployment Benefits Costs Tracker On February 10, 2005, Detroit Edison filed an application requesting MPSC approval of a proposed tracking mechanism for retiree health care costs. The application was filed as required pursuant to the MPSC's November 2004 order.

Electric Industry Restructuring Electric Rates, Customer Choice and Stranded Costs - In 2000, the Michigan Legislature enacted PA 141 that reduced electric retail rates by 5%, as a result of savings derived from the issuance of securitization bonds. The legislation also contained provisions freezing rates through 2003 and preventing rate increases (i.e., rate caps) for small business customers through 2004 and for residential customers through 2005. The price freeze period expired on February 20, 2004 pursuant to an MPSC order.

In addition, PA 141 codified the MPSC's existing electric Customer Choice program and provided Detroit Edison with the right to recover net stranded costs associated with Customer Choice. Detroit Edison was also allowed to defer certain costs to be recovered once rates could be increased, including costs incurred as a result of changes in taxes, laws and other governmental actions.

As required by PA 141, the MPSC conducted a proceeding to develop a methodology for calculating net stranded costs associated with electric Customer Choice. In a December 2001 order, the MPSC determined that Detroit Edison could recover net stranded costs associated with the fixed cost component of its electric generation operations. Specifically, there would be an annual proceeding or true-up before the MPSC reconciling the receipt of revenues associated with the fixed cost component of its generation services to the revenue requirement for the fixed cost component of those services, inclusive of an allowance for the cost of capital.

Any resulting shortfall in recovery, net of mitigation, would be considered a net stranded cost. The MPSC authorized Detroit Edison to establish a regulatory asset to defer recovery of its incurred stranded costs, subject to review in a subsequent annual net stranded cost proceeding.

In July 2003, the MPSC issued an order finding that Detroit Edison had no net stranded costs in 2000 and 2001. Detroit Edison filed a petition for rehearing of the July 2003 order, which the MPSC denied in December 2003. Detroit Edison has appealed.

As previously discussed, the MPSC's November 2004 final order authorized recovery of $44 million of historical stranded costs incurred in 2002, 2003 and January and February 2004 collectible from electric Customer Choice customers through transition charges. Since March 1, 2004, Detroit Edison has recorded

$108 million of additional stranded costs as a regulatory asset as the result of rate caps and higher electric Customer Choice sales losses than included in the 2004 MPSC interim order.

Securitization - Detroit Edison formed The Detroit Edison Securitization Funding LLC (Securitization LLC), a wholly owned subsidiary, for the purpose of securitizing its qualified costs, primarily related to the unamortized investment in the Fermi 2 54 2004 annual report 11

nuclear power plant. In March 2001, the Securitization LLC issued $1.75 billion of securitization bonds, and Detroit Edison sold $1.75 billion of qualified costs to the Securitization LLC.

The Securitization LLC is independent of Detroit Edison, as is its ownership of the qualified costs. Due to principles of consolidation, the qualified costs and securitization bonds appear on the companys consolidated statement of financial position.

The Company makes no claim to these assets. Ownership of such assets has vested in the Securitization LLC and been assigned to the trustee for the securitization bonds. Neither the qualified costs nor funds from an MPSC approved non-bypassable surcharge collected from Detroit Edison's customers for the payment of costs related to the Securitization LLC and securitization bonds are available to Detroit Edison's creditors.

Excess Securitization Savings - In January 2004, the MPSC issued an order directing Detroit Edison to file a report by March 15, 2004, of the accounting of the savings due to securitization and the application of those savings through December 2003. In addition, Detroit Edison was requested to include in the report an estimate of the foregone carrying cost associated with the excess securitization savings. A report was filed on February 16, 2004 in compliance with the MPSC order.

DTE2 Accounting Application In 2003, we began the implementation of DTE2, a Company-wide initiative to improve existing processes and to implement new core information systems, including finance, human resources, supply chain and work management. The new information systems are replacing systems that are approaching the end of their useful lives. We expect the benefits of DTE2 to include lower costs, faster business cycles, repeatable and optimized processes, enhanced, internal controls, improvements in inventory management and reductions in system support costs.

In July 2004, Detroit Edison filed an accounting application with the MPSC requesting authority to capitalize and amortize DTE2 costs, consisting of computer equipment, software and development costs, as well as related training, maintenance and overhead costs. Through December 2004, we have expensed approximately $20 million of training, maintenance and overhead costs pending MPSC action on our application. Detroit Edison is proposing a 15-year amortization period for the costs, exclusive of the computer equipment costs.

Power Supply Cost Recovery Proceedings 2004 Plan Year - An MPSC December 2003 order resumed the PSCR mechanism that had been suspended while rates were frozen. The order authorized a new PSCR factor for all customers effective January 1, 2004. The MPSC's February 2004 interim order provided for a credit of 1.05 mills per kWh compared to a 2.04 mills per kWh charge previously in effect. Detroit Edison will file a 2004 PSCR reconciliation case by March 31, 2005.

2005Plan Year - In September 2004, Detroit Edison filed its 2005 PSCR plan case seeking approval of a levelized PSCR factor of 1.82 mills per kWh above the amount included in base rates.

In December 2004, Detroit Edison filed revisions to its 2005 PSCR plan case in accordance with the November 2004 MPSC rate order.

The revised filing seeks approval of a levelized PSCR factor of up to 0.48 mills per kWh above the new base rates established in the final electric rate order. Included in the factor are power supply costs, transmission expenses and NOx emission allowance costs.

Detroit Edison self-implemented a factor of a negative 2.00 mills per kWh on January 1, 2005. The Michigan Attorney General has filed a motion for summary disposition of this proceeding based on arguments that the PSCR statute requires a fixed 48-month PSCR factor. Woe cannot predict the nature or timing of actions the MPSC will take on this motion.

Transmission Proceedings On November 18, 2004, a FERC order approved a transmission pricing structure to facilitate seamless trading of electricity between MISO and the PJM Interconnection. The pricing structure eliminates layers of transmission charges between the two regional transmission organizations. The FERC noted that the new pricing structure may result in transmission owners facing abrupt revenue shifts. To facilitate the transition to the new pricing structure, the FERC authorized a Seams Elimination Cost Adjustment (SECA),

effective from December 2004 through March 2006. Under MISO's filing with the FERC, Detroit Edison's SECA obligation would be

$2.2 million per month from December 2004 through March 2005.

Detroit Edison has estimated that the SECA charge for the April 2005 through March 2006 period will be approximately $1 million per month. On December 20, 2004, Detroit Edison'filed a request for rehearing with the FERO which states, among other things, that SECA is retroactive ratemaking and is unlawful under the Federal Power Act. Under the MPSC's November 2004 final rate order, transmission expenses are recoverable through the PSCR mechanism. Therefore, SECA charges, if ultimately imposed, should not have a financial impact to Detroit Edison.

Gas Rate Case Rate Request - In September 2003, MichCon filed an application with the MPSC for an increase in service and distribution charges (base rates) for its gas sales and transportation customers. The filing requests an overall increase in base rates of $194 million per year (approximately 7% increase, inclusive of gas costs), beginning January 1,2005. MichCon requested that the MPSC increase base rates by $154 million per year on an interim basis by April 1, 2004.

MPSCInterim Rate Order - In September 2004, the MPSC issued an order granting interim rate relief to MichCon in the amount of

$35 million. The interim rate order was based on a 50% debt and 50% equity capital structure, and an 11.5% rate of return on common equity. Amounts collected are subject to a potential refund pending a final order in this rate case.

AMPSC StaffRecommendation on Final Rate Relief - The Staff has recominended a $76 million increase in base rates compared to MichCon's requested base rate relief of $194 million. The Staff also supports a' provision, proposed by MichCon, that would allow MichCon to recover or refund 90% of uncollectible accounts receivable expense above or below the amount that is reflected in base rates. In addition, the Staff proposed a 50% debt and 50% equity capital structure utilizing a reduced rate of return on common equity'of 11%. MichCon's current allowed rate of return on common equity is 11.5%.

MPSCProposalforDeciron (PFD) - The Administrative Law Judge (ALI) issued a PFD on MichCon's rate request on December 10, 2004. The PFD recommends an increase in base rates of $60 million. The PFD supports the Staff's recommendations 2004 annual report 55

for capital structure, rate of return on common equity and for the proposed reconciliation of uncollectible accounts receivable.

MichCon expects a final order in the first quarter of 2005.

Gas Industry Restructuring In December 2001, the MPSC approved MichCon's application for a voluntary, expanded permanent gas Customer Choice program, which replaced the experimental program that expired in March 2002. The number of customers eligible to participate in the gas Customer Choice program increased over a three-year period.

Effective April 2004, all of MichCon's 1.2 million customers could elect to participate in the Customer Choice program, thereby purchasing their gas from suppliers other than MichCon.

The MPSC also approved the use of deferred accounting for the recovery of implementation costs of the gas Customer Choice program. As of December 2004, approximately 111,000 customers are participating in the gas Customer Choice program.

Gas Cost Recovery Proceedings 2002 Plan Year - In December 2001, the MPSC issued an order that permitted MichCon to implement GCR factors up to $3.62 per thousand cubic feet (Mcf) for January 2002 billings and up to $4.38 per Mcf for the remainder of 2002. The order also allowed MichCon to recognize a regulatory asset of approximately $14 million repre-senting the difference between the $4.38 factor and the $3.62 factor for volumes that were unbilled at December 31, 2001. The regulatory asset is subject to the 2002 GCR reconciliation process. In March 2003, the MPSC issued an order in MichCon's 2002 GCR plan case.

The MPSC ordered MichCon to reduce its gas cost recovery expens-es by $26.5 million for purposes of calculating the 2002 GCR factor due to MichCon's decision to utilize storage gas during 2001 that resulted in a gas inventory decrement for the 2001 calendar year.

Although we recorded a $26.5 million reserve in 2003 to reflect the impact of this order, a final determination of actual 2002 revenue and expenses including any disallowances or adjustment, will be decided in MichCon's 2002 GCR reconciliation case that was filed with the MPSC in February 2003. The Staff and various inter-vening parties in this proceeding are seeking to have the MPSC disallow an additional $26 million, representing unbilled revenues at December 2001. One party has also proposed the disallowance of half of an $8 million payment made to settle Enron bankruptcy issues. The other parties to the case have recommended that the Enron bankruptcy settlement be addressed in the 2003 GCR reconciliation case. An MPSC Administrative Law Judge has recommended disallowances of $26.5 million related to the use of storage gas in 2001 and $26 million related to the December 2001 unbilled issue, and recommended that the $8 million related to the Enron issue be addressed in the 2003 GCR reconciliation case. We have included this item in our testimony in the 2003 GCR reconciliation filed in February 2004. The Staff has recommended that MichCon be allowed to recover the entire $8 million related to the Enron issue. A final order in this proceeding is expected in 2005. In addition, we filed an appeal of the March 2003 MPSC order with the Michigan Court of Appeals. In November 2004, the Michigan Court of Appeals denied the appeal.

2003 Plan Year - In July 2003, the MPSC approved an increase in MichCon's 2003 GCR rate to a maximum of $5.75 per Mcf for the billing months of August 2003 through December 2003.

MichCon's 2003 GCR reconciliation case was filed with the MPSC in February 2004. In November 2004, the ALI issued a PFD in the 2003 reconciliation case. The AW recommended that MichCon recover the full $8 million related to the Enron issue since MichCon had reason to believe at that time that cancellation of the contract was in the best interests of customers and since customers ultimately realized a benefit from the cancellation.

The AW agreed with the MPSC Staff that a $2 million accounting adjustment related to exchange gas be disallowed.

2004 Plan Year - In September 2003, MichCon filed its 2004 GCR plan case proposing a maximum GCR factor of $5.36 per Mcf.

MichCon agreed to switch from a calendar year to an operational year as a condition of its settlement in the 2003 GCR plan case.

The operational GCR year would run from April to March of the following year. To accomplish the switch, the 2004 GCR plan case reflects a 15-month transitional period, January 2004 through March 2005. Under the transition proposal, MichCon would file two reconciliations pertaining to the transition period; one address-ing the January 2004 to March 2004 period, the other addressing the remaining April 2004 to March 2005 period. The plan also proposes a quarterly GCR ceiling price adjustment mechanism.

This mechanism allows MichCon to increase the maximum GCR factor to compensate for increases in market prices, thereby reducing the possibility of a GCR under-recovery. Due to the sustained increase in market prices for natural gas, in June 2004 the MPSC approved a temporary increase in the maximum GCR factor and a contingent factor which resulted in a new temporary maximum factor of $6.62 per Mcf, effective from July 1,2004 until the MPSC issues its final order in this case. As of December 31, 2004, MichCon has accrued a $55 million regulatory asset representing the under-recovery of actual gas costs incurred in 2004, and the 2003 and 2002 GCR under-recovery.

2005-2006 Plan Year - In December 2004, MichCon filed its 2005-2006 GCR plan case proposing a maximum GCR factor of $7.99 per Mcf. The plan includes a quarterly GCR ceiling price adjustment mechanism. This mechanism allows MichCon to increase the maximum GCR factor to compensate for increases in market prices, thereby reducing the possibility of a GCR under-recovery.

Minimum Pension Liability In December 2002, we recorded an additional minimum pension liability as required under SFAS No. 87, with offsetting amounts to an intangible asset and other comprehensive income. During 2003, the MPSC Staff provided an opinion that the MPSC's traditional rate setting process allowed for the recovery of pension costs as measured by SFAS No. 87. Based on the MPSC Staff opinion, management believes that it will be allowed to recover in rates the minimum pension liability associated with its utility operations. In 2004 and 2003, we reclassified approximately $605 million ($393 million net of tax) and $585 million ($380 million net of tax), respectively, of other comprehensive loss associated with the minimum pension liability to a regulatory asset (Note 14).

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

56 2004 annual report 11

NOTE-5 NUCLEAR OPERATIONS General Fermi 2, our nuclear generating plant, began commercial operation in 1988. Fermi 2 has a design electrical rating (net) of 1,150 megawatts. This plant represents approximately 10%

of Detroit Edison's summer net rated capability. The net book balance of the Fermi 2 plant was written off at December 31, 1998, and an equivalent regulatory asset was established. In 2001, the Fermi 2 regulatory asset was securitized. See Note 4 -Regulatory Matters. Detroit Edison also owns Fermi 1, a nuclear plant that was shut down in 1972 and is currently being decommissioned.

The NRC has jurisdiction over the licensing and operation of Fermi 2 and the decommissioning of Fermi 1.

Property Insurance Detroit Edison maintains several different types of property insurance policies specifically for the Fermi 2 plant. These policies cover such items as replacement power and property damage.

The Nuclear Electric Insurance Limited (NEIL) is the primary supplier of these insurance polices.

Detroit Edison maintains a policy for extra expenses, including replacement power costs necessitated by Fermi 2's unavailability due to an insured event. These policies have a 12-week waiting period and provide an aggregate $490 million of coverage over a three-year period.

Detroit Edison has $500 million in primary coverage and $2.25 billion of excess coverage for stabilization, decontamination, debris removal, repair and/or replacement of property and decommissioning. The combined coverage limit for total property damage is $2.75 billion.

For multiple terrorism losses caused by acts of terrorism not covered under the Terrorism Risk Insurance Act (MRIA) of 2002 occurring within one year after the first loss from terrorism, the NEIL policies would make available to all insured entities up to $3.2 billion, plus any amounts recovered from reinsurance, government indemnity, or other sources to cover losses.

Under the NEIL policies, Detroit Edison could be liable for maximum assessments of up to approximately $28 million per event if the loss associated with any one event at any nuclear plant in the United States should exceed the accumulated funds available to NEIL.

Public Liability Insurance As required by federal law, Detroit Edison maintains $300 million of public liability insurance for a nuclear incident. For liabilities arising from a terrorist act outside the scope of TRIA, the policy is subject to one industry aggregate limit of $300 million. Further, under the Price-Anderson Amendments Act of 1988 (Act), deferred premium charges up to $101 million could be levied against each licensed nuclear facility, but not more than $10 million per year per facility. Thus, deferred premium charges could be levied against all owners of licensed nuclear facilities in the event of a nuclear inci-dent at any of these facilities. The Act expired on August 1, 2002.

During 2003, the U.S. Congress extended the Act for commercial nuclear facilities through December 31, 2003. However, provisions of the Act remain in effect for existing commercial reactors.

Legislation to extend the Act in conjunction with comprehensive energy legislation is currently under debate in Congress.

We cannot predict whether Congress will pass the legislation.

Decommissioning The NRC has jurisdiction over the decommissioning of nuclear power plants and requires decommissioning funding based upon a formula. The MPSC and FERC regulate the recovery of costs of decommissioning nuclear power plants and both require the use of external trust funds to finance the decommissioning of Fermi 2. Rates approved by the MPSC provide for the recovery of decommissioning costs of Fermi 2. Detroit Edison is continuing to fund FERC jurisdictional amounts for decommissioning even though explicit provisions are not included in FERC rates. We believe the MPSC and FERC collections will be adequate to fund the estimated cost of decommissioning using the NRC formula.

Detroit Edison has established a restricted external trust to hold funds collected from customers for decommissioning and the disposal of low-level radioactive waste. Detroit Edison collected

$38 million in 2004, $36 million in 2003 and $42 million in 2002 from customers for decommissioning and low-level radioactive waste disposal. Net unrealized investment gains of $17 million and $62 million in 2004 and 2003, respectively, and $39 million in losses in 2002, were recorded as adjustments to the nuclear decommissioning trust funds and regulatory assets. At December 31, 2004, investments in the external trust consisted of approxi-mately 55% in publicly traded equity securities, 43% in fixed debt instruments and 2% in cash equivalents.

At December 31, 2004 and 2003, Detroit Edison had external decommissioning trust funds of $546 million and $474 million, respectively, for the future decommissioning of Fermi 2. At December 31, 2004 and 2003, Detroit Edison had an additional

$18 million and $22 million in trust funds for the decommissioning of Fermi 1. At December 31, 2004 and 2003, Detroit Edison also had an external decommissioning trust fund for low-level radioac-tive waste disposal costs of $26 million and $22 million, respectively.

It is estimated that the cost of decommissioning Fermi 2, when its license expires in 2025, will be $1.0 billion in 2004 dollars and

$3.4 billion in 2025 dollars, using a 6% inflation rate. In 2001, the company began the decommissioning of Fermi 1, with the goal of removing the radioactive material and terminating the Fermi 1 license. The decommissioning of Fermi 1 is expected to be complete by 2009.

As a result of adopting SFAS No. 143, Detroit Edison recorded a retirement obligation liability for the decommissioning of Fermi 1 and 2 and reversed previously recognized decommissioning liabili-ties. At December 31, 2004, we have recorded a liability for the removal of the non-nuclear portion of the plants of $77 million.

Nuclear Fuel Disposal Costs In accordance with the Federal Nuclear Waste Policy Act of 1982, Detroit Edison has a contract with the U.S. Department of Energy (DOE) for the future storage and disposal of spent nuclear fuel from Fermi 2. Detroit Edison is obligated to pay the DOE a fee of 1 mill per kNh of Fermi 2 electricity generated and sold. The fee is a component of nuclear fuel expense. Delays have occurred in the DOE's program for the acceptance and disposal of spent nuclear fuel at a permanent repository. Until the DOE is able to fulfill its obligation under the contract, Detroit Edison is responsible for the spent nuclear fuel storage. Detroit Edison estimates that existing storage capacity will be sufficient until 2007. Detroit Edison is a party in the litigation against the DOE 2004 annual report 57

for both past and future costs associated with the DOE's failure to accept spent nuclear fuel under the timetable set forth in the Act.

NOTE-6 JOINTLY OWNED UTILITY PLANT Detroit Edison has joint ownership interest in two power plants, Belle River and Ludington Hydroelectric Pumped Storage. Ownership information of the two utility plants as of December 31, 2004 was as follow s:

Ludington Beile Hydroelectric River Pumped Storage In-service date 1984-1985 1973 Total plant capacity 1,026 MW 1,872 MW Ownership interest 49 %

Investment (in Millions) 1,581 166 Accumulated depreciation (in Millions) $

740 88

Detroit Edison's ownership interest is 63% in Unit No. 1, 81% of the facilities applicable to Belle River used jointly by the Belle River and St Clair Power Plants and 75% in common facilities used at Unit No. 2 Belle River The Michigan Public Power Agency (MPPA) has an ownership interest in Belle River Unit No. 1 and other related facilities.

The MPPA is entitled to 19% of the total capacity and energy of the plant and is responsible for the same percentage of the plant's operation, maintenance and capital improvement costs.

Ludington Hydroelectric Pumped Storage Consumers Energy Company has an ownership interest in the Ludington Hydroelectric Pumped Storage Plant. Consumers Energy is entitled to 51% of the total capacity and energy of the plant and is responsible for the same percentage of the plant's operation, maintenance and capital improvement costs.

NOTE-7 INCOMETAXES We file a consolidated federal income tax return.

Total income tax expense (benefit) varied from the statutory federal income tax rate for the following reasons:

(Dollars in MillionsJ 2004 2003 2002 Effective federal income tax rate 21.1 %

(34.4)%

(16.7)%

Income before income taxes and minority interest 396 ' $

266 $

465 Less minority interest

_. (212).

(91)

(37)

Income from continuing 502 operations before tax 6087 Income tax expense at 35% statutory rate 213-; $

125 $

175 Section 29tax credits (38) i (241)

(250)

Investment tax credits (8)

(8)

(9)

Depreciation

.:(4),

(4) 2 Employee Stock Ownership

-- " i Plan dividends (5)

(5)

(4)

Other, net 7

10 2

Income tax expense (benefit) from continuing operations 165"! $

(123) $

(84)

The minority interest allocation reflects the adjustment to earnings to allocate partnership losses to third party owners.

The tax impact of partnership earnings and losses are 58 2004 annual report attributable to the partners instead of the partnerships. The minority interest allocation is therefore removed in computing income taxes associated with continuing operations.

Components of income tax expense (benefit) were as follows:

(Millions) 2004 2003 2002 Continuing Operations Current federal and other income tax expense 31 $

14 $

135 Deferred federal income

(

(29 tax expense (benefit) 134 <

(1371 1219) 165-(123)

(84)

Discontinued operations (4) 61 25 Cumulative Effect of Accounting Changes (15)

Total 161 x$

(77) $

(59)

Internal Revenue Code Section 29 provides a tax credit for qualified fuels produced and sold by a taxpayer to an unrelated party during the taxable year. Our Section 29 tax ciedits earned but not utilized totaled $483 million and are carried forward indefinitely as alternative minimum tax credits. The majority of our tax credit properties, including all of our synfuel projects, have received private letter rulings from the Internal Revenue Service (IRS) that provide assurance as to the appropriateness of using these credits to offset taxable income, however, these tax credits are subject to IRS audit and adjustment.

W'se have a net operating loss carryforward of $203 million that expires in years 2018 through 2020. 'We do not believe that a valuation allowance is required, as we expect to utilize the loss carryforward prior to its expiration.

Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences between the tax basis of assets or liabilities and the reported amounts in the financial statements. Deferred tax assets and liabilities are classified as current or noncurrent according to the classification of the related assets or liabilities. Deferred tax assets and liabilities not related to assets or liabilities are classified according to the expected reversal date of the temporary differences.

Deferred tax assets (liabilities) were comprised of the following at December 31:

(Millions) 2004 2003 Property

$ (1,193), i

$(,1124)

Securitized regulatory assets (778)

(827)

Alternative minimum tax credit carryforward 483 497 Merger basis differences 1251 132 Pension and benefits (56)t (50)

Net operating loss 71'1 84 Other 317 380

$ (1,031)

$ (908)

Deferred income tax liabilities

$ ((Z527'1

$(2,525)

Deferred income tax assets 1,496 1 1,617

$ (1,031) 1

$ (908)

The IRS is currently conducting audits of our federal income tax returns for the years 1998 through 2001. In additionl one of our synfuel facilities is under audit by the IRS for 2001. Audits of four of our synfuel facilities for the years 2001 and 2002 were completed successfully during 2004. The Company accrues tax and interest related to tax uncertainties that arise due to actual or potential 1I

disagreements with governmental agencies about the tax treatment of specific items. At December 31, 2004, the Company had accrued approximately $53 million for such uncertainties. We believe that our accrued tax liabilities are adequate for all years.

NOTE-8 COMMON STOCK AND EARNINGS PER SHARE Common Stock In March 2004, we issued 4,344,492 shares of DTE Energy common stock, valued at $170 million. The common stock was contributed to a defined benefit retirement plan.

Under the DTE Energy Company Long-Term Incentive Plan, we grant non-vested stock awards to key employees, primarily management. At the time of grant, we record the fair value of the non-vested awards as unearned compensation, which is reflected as a reduction in common stock. The number of non-vested stock awards is included in the number of common shares outstanding; however, for purposes of computing basic earnings per share, non-vested stock awards are excluded.

Shareholders' Rights Agreement We have a Shareholders' Rights Agreement designed to maximize shareholder value should DTE Energy be acquired. Under certain triggering events, each right entitles the holder to purchase from DTE Energy one one-hundredth of a share of Series A Junior Participating Preferred Stock of DTE Energy at a price of $90.00, subject to adjustment as provided for in the Shareholders' Rights Agreement. The rights expire in October 2007.

Earnings per Share We report both basic and diluted earnings per share. Basic earnings per share is computed by dividing income from continuing operations by the weighted average'number of common shares outstanding during the period. Diluted earnings per share assumes the issuance of potentially dilutive common shares outstanding during the period and the repurchase of common shares that would have occurred with proceeds from the assumed issuance. Diluted earnings per share assume the exercise of stock options, vesting of non-vested stock awards, and the issuance of performance share awards. A reconciliation of both calculations is presented in the following table:

(in Millions, except per share amounts) 2004 2003 2002 Basic Earnings per Share Income from continuing operations 5, 442.6 $

480.4 $ 585.7 Average number of common shares outstanding i§=.:-i172.6 167.7 164.0 Income per share of common stock based on average number of shares outstanding

$ 2.561 $-

287

$3.57 Diluted Earnings per Share Income from continuing operations i S -442.6 480.4 S 585.7.-

Average number of common shares outstanding 172.

167.7, 164.0 Incremental shares from stock-based awards 7

.6

.8 Average number of dilutive shares outstanding 1733 168.3 164.8 Income per share of common stock assuming issuance of incremental shares 2.55 $

2.85 $ 3.55 Options to purchase approximately one million shares of common stock in 2004, five million shares in 2003 and one million shares in 2002 were not included in the computation of diluted earnings per share because the options' exercise price was greater than the average market price of the common shares, thus making these options anti-dilutive. Common stock to be issued in August 2005 associated with the equity-linked securities is not included in the computation of diluted earnings per share as these shares were not dilutive (Note 9).

NOTE-9 LONG-TERM DEBT AND PREFERRED SECURITIES Long-Term Debt Our long-term debt outstanding and weighted average interest rates* of debt outstanding at December 31 was:

Ein Millions) 2004 2003 DTE Energy Debt, Unsecured 6.1 % due 2006 to 2033

$ 1,945 l

$ 2,005 Detroit Edison Taxable Debt.

Principally Secured 6.1 % due 2005 to 2032 1f672 1,485 Detroit Edison Tax Exempt Revenue Bonds 5.6% due 2008 to 2032 11,145 1,175 MichCon Taxable Debt, Principally Secured 6.2% due 2006 to 2033 785:

772 Quarterly Income Debt Securities (QUIDS) 7.5% due 2026 to 2038

,385 385 Non-Recourse Debt A

56 78 Other Long-Term Debt 95 106

,4.6,0831 6,006 Less amount due within one year

' (410)

(382)

$S 5,673

$ 5,624 Securitization Bonds

$ 1,496.

$ 1,585 Less amount due within one year (96)

(89)

'S 1,400 -

$ 1,496 Equity-Linked Securities

-178

$ 185 Trust Preferred - Linked Securities 8.625% due 2038

$ 103 7.8% due 2032 186 186 7.5% due 2044 103

- - -S2894 $ 289

Weighted average interest rates as of December31, 2004 We issued and optionally redeemed long-term debt consisting of the following:

2005,

Issued $400 million of Detroit Edison senior notes in two series,

$200 million of 4.8% series due 2015 and $200 million of 5.45%

series due 2035. The proceeds were used to redeem the'$385 million of 7.5% Quarterly Income Debt Securities due 2026 to 2028.

Detroit Edison redeemed $76 million of 7.5% senior notes and

$100 million of 7.0% remarketed secured notes, which matured February 2005.

2004

MCN Financing 11, an unconsolidated affiliate, redeemed

$100 million of 8.625% Irust Originated Preferred Securities due 2038. Accordingly, the underlying trust preferred-linked securities were also simultaneously redeemed.

2004 annual report 59

Redeemed $60 million of MCN Energy Enterprises 7.12% medium term notes.

Issued $36 million of Detroit Edison 4-7/8% tax-exempt bonds due 2029, the proceeds of which were used to redeem

$36 million of Detroit Edison 6.55% tax-exempt bonds due 2024.

Issued $32 million of Detroit Edison 4.65% tax-exempt bonds due in 2028, the proceeds of which were used to redeem the following Detroit Edison tax-exempt issues: $11.5 million of 6.05% bonds due 2023, $7.5 million of 5.875% bonds due 2024, and $13 million of 6.45% bonds due 2024.

DTE Energy Trust II, an unconsolidated affiliate, issued an aggregate of $100 million of 7.50% Trust Originated Preferred Securities. The proceeds from the issuance were loaned to DTE Energy in exchange for debt securities with essentially the same terms as the related preferred securities.

Issued $250 million of DTE Energy floating rate notes due in 2007. The floating rate is based on 3 month LIBOR plus 0.95%.

These notes may be called at par in June 2005. The proceeds were used to repay short-term borrowings incurred in connec-tion with the June 2004 redemption of $250 million DTE Energy 6.0% senior notes.

Issued $200 million of Detroit Edison 5.40% senior notes due in 2014. The proceeds were used to repay short-term borrowings and for general corporate purposes.

Issued $120 million of MichCon 5.0% senior notes due in 2019.

The proceeds were used to redeem the following two issues:

$52 million of 6.85% senior notes due 2038 and $55 million of 6.85% senior notes due 2039.

2003

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

Redeemed $100 million of DTE Energy 6.17% Remarketed Notes maturing in 2038.

Issued $49 million of Detroit Edison 5.5% tax exempt bonds maturing in 2030.

Redeemed $49 million of Detroit Edison 6.55% tax-exempt bonds maturing in 2024.

Issued $200 million of MichCon 5.7% senior notes maturing in March 2033.

Redeemed $314 million of Detroit Edison taxable debt with an average interest rate of 7.4% and maturities from 2003-2023.

Redeemed $34 million of Detroit Edison 6.875% tax-exempt bonds maturing in 2022.

In the years 2005 - 2009, our long-term debt maturities are

$507 million, $680 million, $597 million, $455 million and

$361 million, respectively.

Remarketable Securities At December 31, 2004, $175 million of notes of Detroit Edison and MfichCon were subject to periodic remarketings. The $100 million scheduled to remarket in February 2005 was optionally redeemed by Detroit Edison, and no remarketings will take place in 2005.

We direct the remarketing agents to remarket these securities at the lowest interest rate necessary to produce a par bid.

In the event that a remarketing fails, we would be required to purchase the securities.

Quarterly Income Debt Securities (QUIDS)

Detroit Edison had three series of QUIDS outstanding at December 31, 2004. Detroit Edison redeemed all of its outstanding QUIDS on March 4, 2005.

Equity-Linked Securities In June 2002, DTE Energy issued 6.9 million equity security units with gross proceeds from the issuance of $172.5 million.

An equity security unit consists of a stock purchase contract and a senior note of DTE Energy. Under the stock purchase contracts, we will sell, and equity security unit holders must buy, shares of DTE Energy common stock in August 2005 for $172.5 million.

The issue price per share and the exact number of common shares to be sold is dependent on the market value of a share in August 2005. The issue price will be not less than $43.25 or more than

$51.90 per common share, with the corresponding number of shares issued of not more than 4.0 million or less than 3.3 million shares. We are also obligated to pay the security unit holders a quarterly contract adjustment payment at an annual rate of 4.15% of the stated amount until the purchase contract settlement date. We recorded the present value of the contract adjustment payments of $26 million in long-term debt with an offsetting reduction in shareholders' equity. The liability is reduced as the contract adjustment payments are made.

Each senior note has a stated value of $25, pays an annual interest rate of 4.60% and matures in August 2007. The senior notes are pledged as collateral to secure the security unit holders' obligation to purchase DTE Energy common stock under the stock purchase contracts. The security unit holders may satisfy their obligations under the stock purchase contracts by allowing the senior notes to be remarketed with proceeds being paid to DTE Energy as consideration for the purchase of stock under the stock purchase contracts. Alternatively, holders may choose to continue holding the senior notes and use cash as consideration for the purchase of stock under the stock purchase contracts.

Net proceeds from the equity security unit issuance totaled

$167 million. Expenses incurred in connection with this issuance totaled $5.6 million and were allocated betwveen the senior notes and the stock purchase contracts. The amount allocated to the senior notes was deferred and will be recognized as interest expense over the term of the notes. The amount allocated to the stock purchase contracts was charged to equity.

Trust Preferred-Linked Securities DTE Energy has interests in various unconsolidated trusts that were formed for the sole purpose of issuing preferred securities and lend-ing the gross proceeds to us. The sole assets of the trusts are debt 60 2004 annual report I

11

securities of DTE Energy with terms similar to those of the related preferred securities. Payments we make are used by the trusts to make cash distributions on the preferred securities it has issued.

We have the right to extend interest payment periods on the debt securities. Should we exercise this right, we cannot declare or pay dividends on, or redeem, purchase or acquire, any of our capital stock during the deferral period.

DTE Energy has issued certain guarantees with respect to payments on the preferred securities. These guarantees, when taken together with our obligations under the debt securities and related indenture, provide full and unconditional guarantees of the trusts' obligations under the preferred securities.

Financing costs for these issuances were paid for and deferred by DTE Energy. These costs are being amortized using the straight-line method over the estimated lives of the related securities.

Cross Default Provisions Substantially all of the net utility properties of Detroit Edison and MichCon are subject to the lien of mortgages. Should Detroit Edison or MichCon fail to timely pay their indebtedness under these mortgages, such failure will create cross defaults in the indebtedness of DTE Energy Corporate.

Preferred and Preference Securities - Authorized and Unissued At December 31, 2004, DTE Energy had 5 million shares of preferred stock without par value authorized, with no shares issued. Of such amount, 1.5 million shares are reserved for issuance in accordance with the Shareholders' Rights Agreement.

At December 31, 2004, Detroit Edison had approximately 6.75 million shares of preferred stock with a par value of

$100 per share and 30 million shares of preference stock with a par value of $1 per share authorized, with no shares issued.

At December 31, 2004, MichCon had 7 million shares of preferred stock with a par value of $1 per share and 4 million shares of preference stock with a par value of $1 per share authorized, with no shares issued.

NOTE-10 SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS In May 2004, DTE Energy entered into a $375 million two-year unsecured revolving credit facility with a group of banks to be utilized for general corporate borrowings. DTE Energy had approximately $148 million of letters of credit outstanding against this facility at December 31, 2004. This agreement requires the company to maintain a debt to total capitalization ratio of no more than.65 to I and an "earnings before interest, taxes, depreciation and amortization" (EBITDA) to interest ratio of no less than 2 to 1. DTE Energy is currently in compliance with these financial covenants.

In October 2004, DTE Energy entered into a $525 million, five-year unsecured revolving credit facility and lowered its existing three-year revolving credit facility from $350 million to $175 million. Detroit Edison and MichCon also entered into similar revolving credit facilities. Detroit Edison entered into a

$206.25 million, five-year facility and lowered its three-year facility from $137.5 million to $68.75 million. MichCon entered into a $243.75 million, five-year facility and lowered its three-year facility from $162.5 million to $81.25 million. The five-year facili-ties replace the October 2003 364-day facilities, which expired.

The three-year revolving credit facilities expire in October 2006.

The five-and three-year credit facilities are with a syndicate of banks and may be utilized for general corporate borrowings, but primarily are intended to provide liquidity support for each of the Companies' commercial paper programs. Borrowings under the facilities will be available at prevailing short-term interest rates.

The agreements require each of the Companies to maintain a debt to total capitalization ratio of no more than.65 to I and an EBITDA to interest ratio of no less than 2 to 1. The Companies are currently in compliance with these financial covenants. Should either Detroit Edison or MichCon have delinquent debt obligations of at least $25 million to any creditor, such delinquency will be considered a default under DTE Energy's credit agreements.

As of December 31, 2004, we had outstanding commercial paper of $402 million and other short-term borrowings of $1 million.

Detroit Edison also has a $200 million short-term financing agree-ment secured by customer accounts receivable. This agreement contains certain covenants related to the delinquency of accounts receivable. Detroit Edison is currently in compliance with these covenants. W\\e had no balances outstanding under this financing agreement at December 31, 2004.

The weighted average interest rates for short-term borrowings were 2.4% and 1.9% at December 31, 2004 and 2003, respectively.

NOTE-11 CAPITAL AND OPERATING LEASES Lessee - We lease various assets under capital and operating leases, including coal cars, a gas storage field, office buildings, a warehouse, computers, vehicles and other equipment. The lease arrangements expire at various dates through 2029. Portions of the office buildings are subleased to tenants.

Future minimum lease payments under non-cancelable leases at December 31, 2004 were:

Capital Operating (in Mlions)

Leases Leases 2005 11 64 2006 13 56 2007 10 47 2008 11 40 2009 11 38 Thereafter 38 378 Total minimum lease payments Less imiputed interest 94 (211 S 623 Present value of net minimum lease payments 73 Less current portion (7)

Non-current portion 66 Total minimum lease payments for operating leases have not been reduced by future minimum sublease rentals totaling $6 million under non-cancelable subleases expiring at various dates to 2020.

Rental expense for operating leases was $75 million in 2004,

$73 million in 2003 and $40 million in 2002.

2004 annual report 61

Lessor - MichCon leases a portion of its pipeline system to the Vector Pipeline Partnership through a capital lease contract that expires in 2020, with renewal options extending for five years.

The components of the net investment in the capital lease at December 31, 2004, were as follows:

(in Millions) 2005 9

2006 9

2007 9

2008 9

2009 9

Thereafter 98 Total minimum future lease receipts 143 Residual value of leased pipeline 40 Less unearned income (101)

Net investment in capital lease 82 Less current portion (1) 81 NOTE-12 FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS We comply with SFAS No. 133, "Accountingfor Derivative Instruments and Hedging Activities," as amended by SFAS No. 138 and SFAS No. 149. Listed below are important SFAS No. 133 requirements:

All derivative instruments must be recognized as assets or liabilities and measured at fair value, unless they meet the normal purchases and sales exemption.

The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated as a hedge and qualifies for hedge accounting.

Special accounting is allowed for a derivative instrument quali-fying as a hedge and designated as a hedge for the variability of cash flow associated with a forecasted transaction. Gain or loss associated with the effective portion of the hedge is recorded in other comprehensive income. The ineffective portion is recorded to earnings. Amounts recorded in other comprehensive income will be reclassified to net income when the forecasted transac-tion affects earnings. If a cash flow hedge is discontinued because it is likely the forecasted transaction will not occur, net gains or losses are immediately recorded to earnings.

Special accounting is also allowed for a derivative instrument qualifying as a hedge and designated as a hedge of the changes in fair value of an existing asset, liability or firm commitment.

Gain or loss on the hedging instrument is recorded into earnings.

An offsetting loss or gain on the underlying asset, liability or firm commitment is also recorded to earnings.

Our primary market risk exposure is associated with commodity prices, credit, interest rates and foreign currency. Wre have risk management policies to monitor and decrease market risks.

We use derivative instruments to manage some of the exposure.

Except for the activities of the Energy Marketing & Trading segment, we do not hold or issue derivative instruments for trading purposes. The fair value of all derivatives is shown as "assets or liabilities from risk management and trading activities" in the consolidated statement of financial position.

Commodity Price Risk Utility Operations Detroit Edison - Detroit Edison generates, purchases, distributes and sells electricity. Detroit Edison uses forward energy, capacity, and futures contracts to manage changes in the price of electricity and fuel. These derivatives are designated as cash flow hedges or meet the normal purchases and sales exemption and are therefore accounted for under the accrual method. There were no commodity price risk cash flow hedges for utility operations at December 31, 2004.

ffichCon - MichCon purchases, stores, transmits and distributes and sells natural gas. MichCon has fixed-priced contracts for portions of its expected gas supply requirements through 2005.

These contracts are designated and qualify for the normal purchases and sales exemption and are therefore accounted for under the accrual method.

i Commodity price risk associated with our utilities is limited due to the PSCR and GCR mechanisms (Note 1).

Non-Utility Operations Energy Marketing & rading - Energy Marketing and Trading markets and trades wholesale electricity and natural gas physical products, trades financial instruments, and provides risk manage-ment services utilizing energy commodity derivative instruments.

Forwards, futures, options and swap agreements are used to manage exposure to the risk of market price and volume fluctua-tions on its operations. These derivatives are accounted for by recording changes in fair value to earnings, usually is adjustments to operating revenues or fuel, purchased power and gas expense.

This fair value accounting better aligns financial reporting with the way the business is managed and its performance measured.

Energy Marketing & Trading experiences earnings volatility as a result of its gas inventory and other non-derivative assets that do not qualify for fair value accounting under U. S. generally accepted accounting principles. Although the risks associated with these asset positions are substantially offset, requirements to fair value the underlying derivatives result in unrealized gains and losses being recorded to earnings that eventually reverse upon settlement.

Energy Services and Biomass - Our Energy Services and Biomass businesses generate Section 29 tax credits. Additionally, through December 2004, Energy Services has sold majority interests in eight of its nine synthetic fuel production plants. Proceeds from the sales are contingent upon production levels, the production qualifying for Section 29 tax credits, and the value of such credits.

Section 29 tax credits are subject to phase out if domestic crude oil prices reach certain levels. See Note 13 for further discussion.

To manage our exposure in 2005 to the risk of an increase in oil prices that could reduce synfuel sales proceeds, we entered into a series of derivative contracts covering a specified number of barrels of oil. The derivatives, coupled with other contracts, economically hedge approximately 65% of our 2005 synfuel cash flow exposure. The derivative contracts involve purchased and written call options that provide for net cash settlement at expiration based on the full year 2005 average New York Mercantile Exchange (NYMEX) trading price of oil in relation to the strike price of each option. If the average NYMEX price of oil in 2005 is less than approximately $56 per barrel, 62 2004 annual report 11

the derivatives will yield no payment. If the average NYMEX price of oil exceeds approximately $56 per barrel, the derivatives will yield a payment equal to the excess of the average NYMEX price over $56 per barrel, multiplied by the number of barrels covered, up to a maximum price of approximately $68 per barrel. The agreements do not qualify for hedge accounting and, as a result, changes in the fair value of the options are recorded currently in earnings. The fair value changes are recorded as adjustments to the gain from selling interests in synfuel facilities and therefore included in the "Asset gains and losses, net" line item in the con-solidated statement of operations.

Gas Production - Our Gas Production business is engaged in natu-ral gas exploration, development and production. We use deriva-tive contracts to manage changes in the price of natural gas. These derivatives are designated as cash flow hedges. Amounts recorded in other comprehensive loss will be reclassified to earnings as the related forecasted production affects earnings through 2013. In 2005, we estimate reclassifying $35 million of losses to earnings.

Credit Risk Our utility and non-utility businesses are exposed to credit risk if customers or counterparties do not comply with their contractual obligations. We maintain credit policies that significantly minimize overall credit risk. These policies include an evaluation of potential customers' and counterparties' financial condition, credit rating, collateral requirements or other credit enhancements such as letters of credit or guarantees. We use standardized agreements that allow the netting of positive and negative transactions associated with a single counterparty Interest Rate Risk W'se use interest rate swaps, treasury locks and other derivatives to hedge the risk associated with interest rate market volatility.

In 2004 and 2000, we entered into a series of interest rate derivatives to limit our sensitivity to market interest rate risk associated with the issuance of long-term debt. Such instruments were designated as cash flow hedges. We subsequently issued long-term debt and terminated these hedges at a cost that is included in other comprehensive loss. Amounts recorded in other comprehensive loss will be reclassified to interest expense as the related interest affects earnings through 2030. In 2005, we estimate reclassifying $6 million of losses to earnings.

Foreign Currency Risk Energy Marketing and Trading has foreign currency forward contracts to hedge fixed Canadian dollar commitments existing under power purchase and sale contracts and gas transportation, contracts. We entered into these contracts to mitigate any price volatility with respect to fluctuations of the Canadian dollar relative to the U.S. dollar. Certain of these contracts are designated as cash flow hedges with changes in fair value recorded to other compre-hensive income. Amounts recorded to other comprehensive inc6me are classified to operating revenues or fuel, purchased power and gas expense when the related hedged item affects earnings.

Fair Value of Other Financial Instruments The fair value of financial instruments is determined by using various market data and other valuation techniques. The table below shows the fair value relative to the carrying value for long-term debt securities. The carrying value of certain other financial instruments, such as notes payable, customer deposits and notes receivable approximate fair value and are not shown.

2004 2003

- FairValue S Carrying Value i FairValue Canyig Value Long-Term Debt i8.5 billion O billion l S 8.5 billion

$ 7.9 billion NOTE-13 COMMITMENTS AND CONTINGENCIES Synthetic Fuel Operations We partially or wholly own nine synthetic fuel production facilities.

Synfuel facilities chemically change coal, including waste and marginal coal, into a synthetic fuel as determined under applica-ble IRS rules. Section 29 of the Internal Revenue Code provides tax credits for the production and sale of solid synthetic fuels produced from coal. To qualify for the Section 29 tax credits, the synthetic fuel must meet three primary conditions: (1) there must be a significant chemical change in the coal feedstock, (2) the product must be sold to an unaffiliated entity, and (3) the produc-tion facility must have been placed in service before July 1,1998.

In addition to meeting the qualifying conditions, a taxpayer must have sufficient taxable income to earn the Section 29 tax credits.

In-Servnce Date - During July 2004, several unaffiliated companies announced that they have been notified that the IRS intends to challenge the placed in service dates for some of their synfuel facilities. If the IRS ultimately prevails, Section 29 credits claimed by these companies would be disallowed. The placed in-service issue is fact-driven and specific to each facility. The in-service dates for eight of our nine synfuel plants have been favorably reviewed by the IRS in cornunction with issuing determination letters and/or recently completed audits. We believe all nine of our synthetic fuel plants meet the required in-service condition.

Through December 31, 2004, we have generated and recorded approximately $512 million in synfuel tax credits.

Oil Pices - To reduce U.S. dependence on imported oil, the Internal Revenue Code provides Section 29 tax credits as an incentive for taxpayers to produce fuels from alternative sources.

This incentive is not deemed necessary if the price of oil increases and provides a natural market for these fuels. As such, the tax credit in a given year is reduced if the Reference Price of oil within that year exceeds a threshold price. The Reference Price of a barrel of oil is an estimate of the annual average wellhead price per barrel for'domestic crude oil, which in recent years has been $3 -$4 lower than the NYMEX price for light, sweet crude oil. The threshold price at which the credit begins to be reduced was set in 1980 and is adjusted annually for inflation.

For 2004, we estimate that the threshold price at which the tax credit would have begun to be reduced was $51.34 and would -

have been completely phased out if the Reference Price reached

$64.45. The Reference Price of oil is estimated to be $37.61 for 2004. We also estimate that the 2005 average wellhead price per barrel of oil would have to exceed approximately $52.37 per barrel to begin phase out and exceed approximately $65.74 per barrel to eliminate the credits. We cannot predict with any accuracy the future price of a barrel of oil.

Numerous recent events have increased domestic crude oil prices, including terrorism, storm-related supply disruptions 2004 annual report 63

and worldwide demand. If the credit is reduced or eliminated in future years, our financial statements would be negatively impacted. Al'e continue to evaluate the current volatility in oil prices and alternatives available to mitigate our exposure to oil prices as part of our synfuel-related risk management strategy.

To manage our exposure to oil prices in 2005, we entered into oil-related derivative contracts. See Note 12 for further discussion.

Environmental Air-The EPA issued ozone transport and acid rain regulations and, in December 2003, proposed additional emission regulations relating to ozone, fine particulate and mercury air pollution.

The new rules have led to additional controls on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide, carbon diox-ide and particulate emissions. To comply with these new controls, Detroit Edison has spent approximately $580 million through December 2004, and estimates that it will spend up to $100 million in 2005 and incur from $700 million to $1.3 billion of additional future capital expenditures over the next five to eight years to satisfy both the existing and proposed new control requirements.

Under the June 2000 Michigan restructuring legislation, beginning January 1, 2004, annual return of and on this capital expenditure, in excess of current depreciation levels, could be deferred in ratemaking, until after the expiration of the rate cap period, presently expected to end on December 31, 2005 upon AIPSC authorization. Under PA 141 and the MPSC's November 2004 final rate order, we believe that prudently incurred capital expenditures, in excess of current depreciation levels, are recoverable in rates.

flater - Detroit Edison is required to examine alternatives for reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of the studies to be conducted over the next several years, Detroit Edison may be required to install additional control technologies to reduce the impacts of the intakes. It is estimated that eve will incur up to $50 million over the next five to seven years in additional capital expenditures for Detroit Edison.

Contaminated Sites - Prior to the construction of major interstate natural gas pipelines, gas for heating and other uses was manufac-tured locally from processes involving coal, coke or oil. Enterprises (MichCon and Citizens) owns, or previously owned, 18 such former manufactured gas plant (MGP) sites. During the mid-1980's, Enterprises conducted preliminary environmental investigations at former MGP sites, and some contamination related to the by-products of gas manufacturing was discovered at each site.

The existence of these sites and the results of the environmental investigations have been reported to the MDEQ.

Enterprises is remediating eight of the former MGP sites and conducting more extensive investigations at five other former MGP sites. Enterprises received MDEQ closure of one site, and a determination that it is not a responsible party for three other sites. Enterprises received closure from the EPA in 2002 for one site.

In 1984, Enterprises established a $12 million reserve for costs associated with enviromnental investigation and remediation activities. During 1993, MichCon received MPSC approval of a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites in excess of this reserve. Enterprises employed outside consultants to evaluate remediation alternatives for these sites, to assist in estimating its potential liabilities and to review its archived insurance policies.

As a result of these studies, Enterprises accrued an additional liability and a corresponding regulatory asset of $35 million during 1995. In early December 2004, Enterprises retained multiple environmental consultants to estimate the projected cost to remediate each MGP facility. The results of the evaluation indicated that the MGP reserve should be set at $24 million.

During 2004, Enterprises spent approximately $2 million investigat-ing and remediating these former MGP sites. At December 31, 2004, the reserve balance was $24 million of which $4.5 million was classified as current. Any significant change in assumptions, such as remediation techniques, nature and extent of contamina-tion and regulatory requirements, could impact the estimate of remedial action costs for the sites and, therefore, have an effect on the Company's financial position and cash flows. However, we anticipate the cost deferral and rate recovery mechanism approved by the MPSC will prevent environmental costs from having a material adverse impact on our results of operations.

Detroit Edison conducted remedial investigations at contaminated sites, including two former MGP sites, the area surrounding an ash landfill and several underground and aboveground storage tank locations. The findings of these investigations indicated that the cost to remediate these sites is approximately $8 million, which is expected to be incurred over the next several years. As a result of the investigation, Detroit Edison accrued an $8 million liability during 2004.

Guarantees In certain circumstances we enter into contractual guarantees.

We may guarantee another entity's obligation in the event it fails to perform. We may provide guarantees in certain indemnification agreements. Finally, we may provide indirect guarantees of the indebtedness of others. Below are the details of specific material guarantees we currently provide. Our other guarantees are not individually material and total approximately $40 million at December 31, 2004.

Sale of Interests in Synfuel Facilities We have provided certain guarantees and indemnities in conjunction with the sales of interests in our synfuel facilities.

The guarantees cover general commercial, environmental and tax-related exposure and will survive until 90 days after expiration of all applicable statute of limitations, or indefinitely, depending on the nature of the guarantee. We estimate that our maximum liability under these guarantees at December 31, 2004 totals $905 million.

Parent Company Guarantee of Subsidiary Obligations We have issued guarantees for the benefit of various non-utility subsidiary transactions. In the event that DTE Energy's credit rating is downgraded below investment grade, certain of these guarantees would require us to post cash or letters of credit valued at approximately $356 million at December 31, 2004.

This estimated amount fluctuates based upon the provisions and maturities of the underlying agreements.

64 2004 annual report 11

Personal Property Taxes Prior to 1999, Detroit Edison, MichCon and other Michigan utilities asserted that Michigan's valuation tables result in the substantial overvaluation of utility personal property. Valuation tables established by the Michigan State Tax Commission (STC) are used to determine the taxable value of personal property based on the property's age. In November 1999, the STC approved new valuation tables that more accurately recognize the value of a utility's personal property. The new tables became effective in 2000 and are currently used to calculate property tax expense.

However, several local taxing jurisdictions have taken legal action attempting to prevent the STC from implementing the new valuation tables and have continued to prepare assessments based on the superseded tables. The legal actions regarding the appropriateness of the new tables were before the Michigan Tax Tribunal (MIT) which, in April 2002, issued its decision essentially affirming the validity of the STC's new tables. In June 2002, petitioners in the case filed an appeal of the MITs decision with the Michigan Court of Appeals. In January 2004, the Michigan Court of Appeals upheld the validity of the new tables. With no further appeal by the petitioners available, the MTT began to schedule utility personal property valuation cases for Prehearing General Calls. Detroit Edison and MichCon have filed motions and the AMT agreed to place their cases in abeyance pending the conclusion of settlement negotiations being conducted by State of Michigan Treasury officials. On February 14, 2005, MIT issued a scheduling order that lifts the prior abeyances in a significant number of Detroit Edison and MichCon appeals.

The scheduling order sets litigation calendars for these cases extending into mid-2006.

Detroit Edison and MichCon continue to record property tax expense based on the new tables. Detroit Edison and MichCon will continue through settlement or litigation to seek to apply the new tables retroactively and to ultimately resolve the pending tax appeals related to 1997 through 1999.

This is a solution supported by the STC in the past. To the extent that settlements cannot be achieved with the jurisdic-tions, litigation regarding the valuation of utility property will delay any recoveries by Detroit Edison and MichCon.

Other Commitments Detroit Edison has an Energy Purchase Agreement to purchase steam and electricity from the Greater Detroit Resource Recovery Authority (GDRRA). Under the Agreement, Detroit Edison will purchase steam through 2008 and electricity through June 2024.

In 1996, a special charge to income was recorded that included a reserve for steam purchase commitments in excess of replacement costs from 1997 through 2008. The reserve for steam purchase commitments is being amortized to fuel, purchased power and gas expense with non-cash accretion expense being recorded thr6ugh 2008. We purchased $42 million of steam and electricity in 2004,

$39 million in 2003 and $37 million in 2002. We estimate steam and electric purchase commitments through 2024 will not exceed

$472 million. As discussed in Note 3 - Dispositions, in January 2003, we sold the steam heating business of Detroit Edison to Thermal Ventures II, LP. Due to terms of the sale, Detroit Edison remains contractually obligated to buy steam from GDRRA until 2008 and recorded an additional liability of $20 million for future commitments. Also, we have guaranteed bank loans that Thermal Ventures II, LP may use for capital improvements to the steam heating system.

In 2004, we modified our future purchase commitments under a transportation agreement with an interstate pipeline company and terminated a related long-term gas exchange (storage) agreement.

Under the gas exchange agreement, we received gas from the customer during the summer injection period and redelivered the gas during the winter heating season. The agreements were at rates that were not reflective of current market conditions and had been fair valued under accounting principles generally accepted in the U.S. In 2002, the fair value of the transportation agreement was frozen when it no longer met the definition of a derivative as a result of FERC Order 637. The fair value amounts were being amortized to income over the life of the related agreements, representing a net liability of approximately

$75 million as of December 31, 2003. As a result of the contract modification and termination, we recorded an adjustment to the net liability increasing 2004 earnings by $48 million, net of taxes.

At December 31, 2004, we have entered into numerous long-term purchase commitments relating to a variety of goods and services required for our business. These agreements primarily consist of fuel supply commitments and energy trading contracts.

We estimate that these commitments will be approximately

$7.3 billion through 2027. We also estimate that 2005 base level capital expenditures will be $1.1 billion. We have made certain commitments in connection with expected capital expenditures.

Bankruptcies We purchase and sell electricity, gas, coal and coke from and to numerous companies operating in the steel, automotive, energy and retail industries. Several customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. We have negotiated or are currently involved in negotiations with each of the companies, or their successor companies, that have filed for bankruptcy protection. We regularly review contingent matters relating to purchase and sale contracts and record provisions for amounts considered probable of loss. We believe our previously accrued amounts are adequate for probable losses. The final resolution of these matters is not expected to have a material effect on our financial statements in the period they are resolved.

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

See Note 4 and Note 5 for a discussion of contingencies related to Regulatory Matters and Nuclear Operations.

2004 annual report 65

NOTE-14 RETIREMENT BENEFITS AND TRUSTEED ASSETS Measurement Date In the fourth quarter of 2004, we changed the date for actuarial measurement of our obligations for benefit programs from December 31 to November 30. We believe the one-month change of the measurement date is a preferable change as it allows time for management to plan and execute its review of the completeness and accuracy of its benefit programs results and to fMlly reflect the impact on its financial results. The change did not have a material effect on retained earnings as of January 1, 2004, and income from continuing operations, net income and related per share amounts for any interim period in 2004. Accordingly, all amounts reported in the following tables for balances as of December 31, 2004 are based on a measurement date of November 30, 2004. Amounts reported in tables for the year ended December 31, 2004 and for balances as of December 31,2003 are based on a measurement date of December 31, 2003. Amounts reported in tables for the year ended December 31, 2003 are based on a measurement date of December 31,2002.

Qualified and Nonqualified Pension Plan Benefits We have defined benefit retirement plans for eligible represented and nonrepresented employees. The plans are noncontributory, cover substantially all employees and provide retirement benefits based on the employees' years of benefit service, average final compensation and age at retirement. Certain represented and nonrepresented employees are covered under cash balance benefits based on annual employer contributions and interest credits. Our policy is to fund pension costs by contributing the minimum amount required by the Employee Retirement Income Security Act (ERISA) and additional amounts when we deem appropriate. We do not anticipate making a contribution to our qualified pension plans in 2005.

Wsle also maintain supplemental nonqualified, noncontributory, retirement benefit plans for selected management employees.

These plans provide for benefits that supplement those provided by DTE Energy's other retirement plans.

Net pension cost (credit) includes the following components:

Qualified Pension Plans Nonqualified Pension Plans (in Millions) 2004 2003 2004 2003 Measurement Date Nov.30 Dec. 31 Nov.30.

Dec. 31 Accumulated Benefit Obligation-End of Period

$ 2.689 S 2,556

$ 54 -

$ 57 Projected Benefit 3

Obligation-Beginning of Period $ Z745

$ Z499

$ 59-x l $ 50 ServiceCost

.58 48 2,,

2 Interest Cost 168 164 3

4 Actuarial Loss (Gain) 76 201 (4)'

6 Benefits Paid 7 (149) 1159)

(4)V (3)

Plan Amendments 1

(8)

Projected Benefit Obligation-End of Period

$ Z899

$ 2,745

$ 56X.

$ 59 Plan Assets at Fair Value-Beginning of Period

$ 2,348

$ 1,845 i

Actual Retum on PlanAssets

.-.196 440 '

Company Contributions 170 222 4

3 Benefits Paid (149)

(159)

(4) 1-(31 Plan Assets at Fair Value-End of Period

$2,565

$ 2,348 s$

Funded Status of the Plans

$ (334) $ (397)

$(56J.

$ (59)

Unrecognized Netloss 1,043 1,010

15.

18 Priorservice cost 34 41 1

3 Net Amount Recognized at Measurement Date 743 654 (40)K6 (381 Company Contribution in December 2004

1.

Net Amount Recognized

-End of Period 743 654

$ (39)

$ (38)

Amount Recorded as Prepaid pension assets 184 181 Accrued pension liability (212)

(287)

(53)-

(58)

Regulatory asset 594 572 11 13 Accumulated other comprehensive loss

.139 147 2'

4 Intangible asset 38 41 1.-

3 743 654

$ (39)

$ (38)

Assumptions used in determining the projected benefit obligation and net pension costs are listed below:

2004 2003 2002 Projected Benefit Obligation Discount rate 6.000/%

6.25%

6.75%

Annual increase in future compensation levels 4.0%

4.0%

Net Pension Costs Discount rate 6.25%

6.75%

7.25%

Annual increase in future compensation levels 4.0%/6 4.0%

4.0%

Expected long-term rate of return on Plan assets

-9.00/0 9.0%

9.5%

At December 31, 2004, the benefits related to our qualified and non-qualified plans expected to be paid in each of the next five years and in the aggregate for the five fiscal years thereafter are as follows:

in Millions) 2005 S. 173 2006 177 2007

-182 2008

'189 2009 194 2010 - 2014 1,091 Total

$ 2,006 Qualified Pension Plans Nonqualified Pension Plans (in Millions) 2004 2003 2002 2004 2003 2002 Service Cost S 58

$ 48

$ 43

-S 2

$ 2

$ 1 Interest Cost 168 164 162 3

4 3

Expected Return on Plan Assets (216) 1211)

(223)

Amortization of Net loss

63 38 2

1 1

1 Prior service cost

.8 8

9 1

Nettransition asset (2)

Net Pension Cost(Credit)

S 81

$ 47

$ (9) 6

$ 7

$ 6 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 financial position at December 31:

66 2004 annual report II

We employ a consistent formal process in determining the long-term rate of return for various asset classes. We evaluate input from our consultants, including their review of historic financial market risks and returns and long-term historic relationships between the asset classes of equities, fixed income and other assets, consistent with the widely accepted capital -

market principle that asset classes with higher volatility generate a greater return over the long-term. Current market factors such as inflation, interest rates, asset class risks and asset class returns are evaluated and considered before long-term capital market assumptions are determined. The long-term portfolio return is also established employing a consistent formal process, with due consideration of diversification, active investment management and rebalancing. Peer data is reviewed to check for reasonableness.

We employ a total return investment approach whereby a mix of equities, fixed income and other investments are used to maximize the long-term return of plan assets consistent with prudent levels of risk. The intent of this strategy is to minimize plan expenses over the long-term. Risk tolerance is established through consideration 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, equity investments are diversified -

across U.S. and non-U.S. stocks, growth and value investment styles, and large and small market capitalizations. Other assets such as:

private equity and absolute return funds are used judiciously to enhance long term returns while improving portfolio diversifica--

tion. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on an ongoing basis through annual liability measurements, periodic asset/liability studies, and quarterly investment portfolio reviews.

Our plans' weighted-average asset allocations by asset category at December 31 were as follows:

2004 2003 Equity Securities 69%-

67%

DebtSecurities 26,

27 Other 5

6 V. 1100%-

100%1 Our plans' weighted-average asset target allocations by asset category at December 31, 2004 were as follows:

Equity Securities 65%

Debt Securities 28 Other In December 2002, we recognized an additional minimum pension liability as required under SFAS No.: 87, aEmployers'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, an intangible asset and other comprehensive loss. In 2003, we reclassified $572 million of other comprehensive loss related to Detroit Edison's minimum pension liability to a regulatory asset after the MPSC Staff provided an opinion that the MPSC's traditional rate setting process allowed for the recovery of pension costs as measured by SFAS No. 87. The additional minimum pension liability, regulatory asset, intangible asset and other comprehensive loss are adjusted in December of each year based on the plans' funded status.

We also sponsor defined contribution retirement savings plans.

Participation in one of these plans is available to substantially all represented and nonrepresented employees. Wo'e match employee contributions up to certain predefined limits based upon eligible compensation, the employee's contribution rate and, in some cases, years of credited service. The cost of these plans was

$28 million in 2004, $26 million in 2003 and $25 million in 2002.

Other Postretirement Benefits We provide certain postretirement health care and life insurance benefits for employees who are eligible for these benefits. Our policy is to fund certain trusts to meet our postretirement benefit obliga-tions. Separate qualified Voluntary Employees Beneficiary Association (VEBA) trusts exist for represented and nonrepresented employees.

Net postretirement cost includes the following components:

fin Millions) 2004 2003 ' 2002 Service Cost 3$

41 $

37 $

30 Interest Cost i'92 r 87 78 Expected Return on Plan Assets (56) 147)

(59)

Amortization of Net loss 43 31 3

Prior service cost (3)

(3)

(1)

Nettransition obligation 8

13 19 Net Postretirement Cost S 125$ $

118 $

70 The following table reconciles the obligations, assets and funded status of the plans including amounts recorded as accrued postretirement cost in the consolidated statement of financial position at December 31:

(in MWlions) 2004 2003 Measurement Date Nov.30 Dec. 31 Accumulated Postretirement Benefit Obligation-Beginning of Period S 1=,82

$ 1,494 Service Cost c--

-41 37 Interest Cost 92 87 Actuarial Loss

'4 146 162 Plan Amendments 7 i (126)

Benefits Paid 72 (75)

(72)

Accumulated Postretirement Benefit Obligation-End of Period

$ 1,793

$ 1,582 Plan Assets at Fair Value-Beginning of Period

,$586 537 Actual Return on Plan Assets 53 114 Company Contributions 40 Benefits Paid (65)

Plan Assets at Fair; Value-End of Period

$ '679 586 Funded Status of the Plans-($11 14Y

$ (996)

Unrecognized Net loss

-811 705 Prior service cost Y(8)

(27)

Nettransition obligation 58 74 Accrued Postretirement

-X Liability at Measurement Date (253)-

(244)

Company Contribution And Benefit Payments in December 2004 (20)

Accrued Postretirement Liability-End of Period

$ (273)

$ (244) 2004 annual report 67

Assumptions used in determining the projected benefit obligation and net benefit costs are listed below 2004 2003 2002 Projected Benefit Obligation Discount rate 6.00 %;

6.25%

6.75%

Net Benefit Costs Discount rate 6.250h 6.75%

7.25%

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

9.0%

9.5%

Benefit costs were calculated assuming health care cost trend rates beginning at 9.0% for 2005 and decreasing to 5.0% in 2010 and thereafter for persons under age 65 and decreasing from 8.0% to 5.0% for persons age 65 and over. A one-percentage-point increase in health care cost trend rates would have increased the total service cost and interest cost components of benefit costs by $20 million and increased the accumulated benefit obligation by $177 million at December 31, 2004. A one-percentage-point decrease in the health care cost trend rates would have decreased the total service and interest cost components of benefit costs by

$17 million and would have decreased the accumulated benefit obligation by $157 million at December 31, 2004.

Effective 2005, we amended our postretirement health care plan to provide for some enhancements. The changes increased our expected 2005 postretirement cost by $6 million.

At December 31, 2004, the benefits expected to be paid, including prescription drug benefits, in each of the next five years and in the aggregate for the five fiscal years thereafter are as follows:

ran Milions) 2005

. 97 2006 106 2007 110 2008 113 2009 120 2010 - 2014 665 Total

$ 1,211 The process used in determining the long-term rate of return for assets and the investment approach for our other postretirement benefits plans is similar to those previously described for our qualified pension plans.

Our plans' weighted-average asset allocations by asset category at December 31 were as follows:

_2004 2003 Equity Securities 68%-

66%

Debt Securities 28-30 Other 4

4 100%--,

100%

Our plans' weighted-average asset target allocations by asset category at December 31, 2004 were as follows:

Equity Securities 65%

Debt Securities 28 Other 1

.100%

In December 2003, the Medicare Act was signed into law which provides for a non-taxable federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least "actuarially equivalent" to the benefit established by law. As discussed in Note 2, we adopted FSP No. 106-2 in 2004, which provides guidance on the accounting for the Medicare Act. As a result of the adoption, our accumulated postretirement benefit obligation for the subsidy related to benefits attributed to past service was reduced by approximately $95 million at January 1, 2004 and was accounted for as an actuarial gain.

The effects of the subsidy reduced net periodic postretirement benefit costs by $16 million in 2004. The impact of the Medicare Act on the components of other postretirement benefit costs for the year ended December 31 was as follows:

(in Millions)

Reduction in service cost 2

Reduction in interest cost

. 6 Amortization of actuarial gain Decrease in postretirement benefit cost

$ 16 At December 31, 2004, the gross amount of federal subsidies expected to be received in each of the next five years and in the aggregate for the five fiscal years thereafter was as follows:

ain Millions) 2005 2006 11 2007 1-2008 12 2009 12 2010- 2014 69 Total

$ 115 Grantor Trust MichCon maintains a Grantor Trust that invests in life insurance contracts and income securities. Employees and retirees have no right, title or interest in the assets of the Grantor Trust, and MichCon can revoke the trust subject to providing the MPSC with prior notification. We account for our investment at fair value with unrealized gains and losses recorded to earnings.

NOTE-15 STOCK-BASED COMPENSATION The DTE Energy Stock Incentive Plan permits the grant of incentive stock options, non-qualifying stock options, stock awards, performance shares and performance units. A maximum of 18 million shares of common stock may be issued under the plan. Participants in the plan include our employees and members of our Board of Directors. As of December 31, 2004, no performance units have been granted under the plan.

Options Options are exercisable according to the terms of the individual stock option award agreements and expire 10 years after the date of the grant. The option exercise price equals the fair value of the stock on the date that the option was granted. Stock option activity was as follows:

I 68 2004 annual report 11

Weighted Number of Average Options Exercise Price Outstanding at December 31, 2001 (1,678,870 exercisable) 5,281,624

$ 38.51 Granted 1,334,370

$ 42.08 Exercised (678,715)

$ 34.64 Canceled (456,684)

$ 38.74 Outstanding at December 31,2002 (2,285,323 exercisable) 5,480,595

$ 39.87 Granted 1,654,879

$ 40.56 Exercised (329,528)

$ 35.88 Canceled (152,824)

$ 42.67 Outstanding at December 31, 2003 i a

=

(3,506,038 exercisable) r, 6,653,122.

$40.18 Granted j 1,3 00,9OO

$S3941 Exercised j^ ; (891,353)

$34.94F Canceled (356,00) 4306 Outstanding at December 31, 2004 (3,939,939 exercisable at a weighted average exercise price of $40.52) 6,706,669 4057 The number, weighted average exercise price and weighted average remaining contractual life of options outstanding were as follows:

Weighted Weighted Average Range of Number of Average Remaining Exercise Prices Options Exercise Price Contractual Life

$27.62-$38.04 649,604

$ 31.70 5.02 years

$38.60- $42.44 4,594,837

$ 40.68 7.65 years

$42.60-$44.54 690,950

$ 42.70 6.38 years

$45.28-$46.74 771,278

$ 45.47 6.51 years 6,706,669

$ 40.57 7.13 years W&e account for option awards under APB Opinion 25. Accordingly, no compensation expense has been recorded for options granted.

As required by SFAS No. 123, we have determined the fair value for these options at the date of grant using a Black-Scholes based option pricing model and the following assumptions:

2004 2003 2002 Risk-free interest rate 3.55%

2.93 %

5.33 %

Dividend yield 523%

4.97 %

4.90%

Expected volatility 20.89 %

19.79 %

Expected life 6 years 6 years 6 years Fair value per option

-$4.46

$4.78

$6.25 Stock Awards Stock awards granted under the plan are restricted for varying periods, which are generally for three years. Participants have all rights of a shareholder with respect to a stock award, including the right to receive dividends and vote the shares.; Prior to vesting in stock awards, the participant: (i) may not sell, transfer, pledge, exchange or otherwise dispose of shares; (ii) shall not retain custody of the share certificates; and (iii) will deliver to us a stock power with respect to each stock award.

The stock awards are recorded at cost that approximates fair value on the date of grant. We account for stock awards as unearned compensation, which is recorded as a reduction to common stock.

The cost is amortized to compensation expense over the vesting period. Stock award activity for the years ended December 31 was:

2004 2003 2002 Restricted common shares awarded I 209,650 102,060 113,410 Weighted average market priceofsharesawarded IS 39.95.

$ 41.39

$ 42.92 Compensation cost charged against income (in thousands)

$ 5,616

$ 6,366

$ 4,101 Performance Share Awards Performance shares awarded under the plan are for a specified number of shares of common stock that entitles the holder to receive a cash payment, shares of common stock or a combination thereof. The final value of the award is determined by the achieve-ment of certain performance objectives. The awards vest at the end of a specified period, usually three years. We account for performance share awards by accruing compensation expense over the vesting period based on: (i) the number of shares expected to be paid which is based on the probable achievement of performance objectives; and (ii) the fair value of the shares.

For 2004,2003 and 2002, we recorded compensation expense totaling $6.1 million, $5.5 million and $3.6 million, respectively.

During the vesting period, the recipient of a performance share award has no shareholder rights. However, recipients will be paid an amount equal to the dividend equivalent on such shares.

Performance share awards are nontransferable and are subject to risk of forfeiture. As of December 31, 2004, there were 619,044 performance share awards outstanding.

NOTE-16 SEGMENT AND RELATED INFORMATION We operate our businesses through three strategic business units (Energy Resources, Energy Distribution and Energy Gas). Each business unit has utility and non-utility operations. The balance of our business consists of Corporate & Other. Based on this structure, we set strategic goals, allocate resources and evaluate performance.

This results in the following reportable segments.

Energy Resources

Utility -Power Generation operations include the power

- generation services of Detroit Edison, the company's electric utility. Electricity is generated from Detroit Edison's numerous fossil plants or its nuclear plant and sold throughout Southeastern Michigan to residential, commercial, industrial and wholesale customers.

Non-utility

-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 Aarketing & rading consists of the electric and gas marketing and trading operations of DTE Energy frading Company and the natural gas marketing and trading operations of DTE Enterprises. Energy Marketing & Trading enters into forwards, futures, swaps and option contracts as part of its trading strategy.

- Other Non-utility operations consist primarily of businesses involved in coal services and landfill gas recovery. Also includes administrative and general expenses not allocated to other non-utility businesses.

2004 annual report 69

Energy Distribution

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

Non-utility operations include businesses that assemble, market, distribute and service a broad portfolio of distributed generation products, provides application engineering, and monitors and manages system operations.

Energy Gas

Utility operations 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-utility operations include the production of gas and the gather-ing, processing and storing of gas. Certain pipeline and storage assets are supported by the Energy Marketing & rTading segment Corporate & Other includes administrative and general expenses, and interest costs of DTE Energy corporate that have not been allocated to the utility and non-utility businesses. Corporate &

Other also includes various other non-utility operations, including investments in new emerging energy technologies.

The income tax provisions or benefits of DTE Energy's subsidiaries are determined on an individual company basis and recognize the tax benefit of Section 29 tax credits and net operating losses. The subsidiaries record income tax payable to or receivable from DTE Energy resulting from the inclusion of its taxable income or loss in DTE Energy's consolidated tax return. Inter-segment revenues primarily consist of power sales, gas sales and coal transportation services between Energy Resources Utility-Power Generation, Energy Services, Energy Marketing & Trading and Non-utility Other, and Energy Gas-Non-utility. DTE Energy's interest income totaled $55 million in 2004, $37 million in 2003 and $29 million in 2002, and is primarily associated with the Energy Services and Corporate & Other segments. Financial data of the business segments follows:

a.. WO 14 Energy Resources Utility-Power Generation

$ 2210

$ 272

$ 167

$ 23

$ 62

$ 8,288

$ 406

$ 332 Non-utility Energy Services 1,089 82 33 64 188 1,790 41 17 Energy Marketing & Trading 665 3

5 46 92 1,098 17 8

Other 576 8

3 (11) 1 126 4

13 Total Non-utility 2,330 93 41 99 281 3,014 62 38 Total Energy Resources 4,540 365 208 122 343 11,302 468 370 Energy Distribution Utility-Power Distribution 1,358 251 113 41 88 4,554 796 370 Non-utility 46 2

2 (10)

(19) 64 16 1

1,404 253 115 31 69 4,618 812 371 Energy Gas Utility-Gas Distribution 1,682 103 58 (9) 20 3,128 772 113 Non-utility 119 20 11 11 21 549 15 48 1,801 123 69 2

41 3,677 787 161 Corporate & Other 16 3

198 10 (10) 2,275 2

Reconciliation & Eliminations (647)

(72)

(584)

Total from Continuing Operations

$ 7,114

$ 744

$ 518

$165 443 21,288 2,067 904 Discontinued Operations (Note 3)

(12) 9 Total

$ 431

$21,297

$2,067

$ 904 Electric Utility

$ 3,568

$ 523

$ 280

$ 64

$ 150

$12,842

$1,202

$ 702 Gas Utility 1,682 103 58 (9) 20 3,128 772 113 Non-utility 2,495 115 54 100 283 3,627 93 87 Corporate & Other 16 3

198 10 (10) 2,275 2

Reconciliation & Eliminations (647)

(72)

(584)

Total from Continuing Operations

$ 7,114

$ 744

$ 518

$165 443 21,288 2,067 904 Discontinued Operations (Note 3)

Total (12) 9

$ 431

$21,297

$2,067

$ 904 70 2004 annual report Il

I-.

.t Energy Resources Utility-PowerGeneration S 2,448

$ 224

$ 157

$135

$235

$ 7,216

$ 406

$ 340 Non-utility 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-utility 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 Utility-Power Distribution 1,247 249 127 10 17 5,333 796 240 Non-utility 39 2

(8)

(15) 65 12 1

1,286 251 127 2

2 5,398 808 241 Energy Gas Utility-Gas Distribution 1,498 101 58 29 3,021 776 99 Non-utility 90 18 8

14 29 518 15 28 1,588 119 66 14 58 3,539 791 127 Corporate & Other 12 219 (28)

(57) 2,383 4

Reconciliation & Eliminations (283)

(47)

(636)

Total from Continuing Operations

$ 7,041

$ 687

$ 546

$1123) 480 20,739 2,067 751 Discontinued Operations (Note 3) 68 14 Cumulative Effect of Accounting Changes (27)

Total

$ 521

$20,753

$2,067

$ 751 Electric Utility

$ 3,695

$ 473

$284

$145

$252

$12,549

$1,202

$ 580 Gas Utility 1,498 101 58 29 3,021 776 99 Non-utility 2,119 113 E 32 (240) 256 3,422 89 68 Corporate & Other 12 219 (28)

(57) 2,383 4

Reconciliation & Eliminations (283)

(47)

(636)

Total from Continuing Operations S 7.041

$ 687

$ 546

$S123) 480 20,739 2,067 751 Discontinued Operations (Note 3)

Cumulative Effect of Accounting Changes Total 68 (27)

S 521 14

$20.753

$2.067

$ 751 68 127) 2004 annual report 71

Energy Resources Utility-Power Generation

$ 2711

$ 331 S 184

$120

$241

$ 7,334

$ 406

$ 395 Non-utility 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

a Total Non-utility 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 Utility-Power Distribution 1,343 246 127 58 111 4,154 796 290 Non-utility 39 2

1 (9)

(16) 60 12 2

1,382 248 128 49 95 4,214 808 292 Energy Gas Utility-Gas Distribution 1,369 104 57 36 66 2,857 776 93 Non-utility 87 19 6

14 26 504 16 32 1,456 123 63 50 92 3,361 792 125 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 19,353 2068 974 Discontinued Operations (Note 3) 46 632 44 10 Total

$632

$19,985

$2,112

$ 984 Electric Utility

$ 4,054

$ 577

$311

$178

$352

$11,488

$1,202

$ 685 Gas Utility 1,369 104 57 36 66 2,857 776 93 Non-utility 1,554 114 45 (269) 224 3,178 90 172 Corporate & Other 16 232 (32)

(56) 2,378 24 Reconciliation & Eliminations (264)

(58)

(76) 3 (548)

Total from Continuina Operations

$ 6.729 S 737

$ 569

$ (841 586 19,353 2,068 974 Discontinued Operations (Note 3)

Total 46 63Z 44 109

$632

$19,985

$2,112

$ 984 72 2004 annual report 1l

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. We account for the operations of ITC and SMGC as discontinued operations (Note 3).

(in Millions, exceptper share amoun1s)

=

S}

Operating Revenues 2093W $

1.501 *$

1,594 1926 I$

1114 Operating Income S368 9

173 S

210 84$

Net Income (Loss)

From continuing operations 197 S

35 S

93 Ila 1

4 3 Discontinued operations (7)

(5)

(12)

Total Sr 190'>

35 93$

113:$S *.431 Basic Earnings (Loss) per Share From continuing operations 1.16 -

.20

.54

.- 8 2.56 Discontinued operations (0.04)

(.3)

(06)

Total S

1.12

$1-Y -

.20.

.54

.65§-

$i 2.50 Diluted Earnings (Loss) per Share i

From continuing operations

$ S 1.15$-

$0 S-

.546 j.6

-55 Discontinued operations (0.04)

(.03)

.06)

Total 1.11 S

.20

.54

.65 S

2.49

'S

'7-Operating Revenues 2095 1,600 1,654 1,692 7,041 Operating Income 217 71 232 227 747 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) 176 229 521 Basic Earnings (Loss) per Share From continuing operations

.65

(.22i 1.07 1.36 2.87 Discontinued operations

.44

(.01)

(.02)

.41 Cumulative effect of accounting changes

(.17)

Total

.92 1.23) 1.05 136 3.11 Diluted Earnings (Loss) per Share From continuing operations

.64

(.22) 1.06

.1.36 2.85 Discontinued operations

.44

(.01)

(.02)

.40 Cumulative effect of accounting changes

(.16)

Total

.92

(.23) 1.04 1.36 3.09 (1) Previously reported firstquarter 2004 amounts have been edjusted to reflectthe retroactive adoption of FSP No. 106-2, relating to the impact of the Medicare Act on postretirement benefit costs (Note 2).

2004 annual report 73

statistical review MIN

.- I.

0.

Operating Revenues Utlity 5,250 5,193 5,423 4,659 Non-utifty (1) 1,864 1,848 1,306 1,128 Total S

7,14 4'. i S

7,041 6,729 5,787 Net Income Utility 170 281 418 198 Non-utility (1) 273 199 168 111 443:

480 586 309 Discontinued Operations 112)--

68 46 20 Cumulative Effect of Accounting Changes (27) 3 431 521 632 332 Diluted Earnings per Share Utility

.98 1.67 2.53 1.29 Non-utility (1) 1.57 1.18 1.02 0.72 2.55 2.85 3.55 2.01 Discontinued Operations (0.06)

.40

.28

.13 Cumulative Effect of Accounting Changes

(.16)

.02 2.49 3.09 3.83 2.16 Electric Utility Deliveries (Millions of kMh) 52,416 53,194 54,105 51,516 Electric Utility Customers at Year End (Thousands) 2,147 2,132 2,136 2,125 Gas Utility Deliveries (Bcf)(2)

- 854-909 837 917 Gas Utility Customers at Year End (Thousands)(2) 1,258='

1,249 1,267 1,235 Financial Position at Year End Net property (3) 10,491 10,324 S

10,542 10,255 Total assets (3) 21,297 20,753 19,985 19,587 Long-term debt, including capital leases S.

7,606 7,669 7,803 7,928 Total shareholders' equity 5,548 5,287 4,565 4,589 Common Share Data Dividends declared per share 2.06 2.06 2.06 2.06 Average shares outstanding-diluted (millions) 173 168 165 154 Book value per share 31.85 31.36 27.26 28.48 Market price: High 45.49 S

49.50 47.70 47.13 Low 37.88, 34.00 33.05 33.13 Year end

$ r 43.13 39.40 46.40 41.94 Miscellaneous Financial Data Cash flow from operations 995 950 996 811 Capital expenditures 904 751 984 1,096 Employees atyear end 11,207 11,099 11,095 11,030 (1) Includes Corporate & Other and/or eliminations.

(2) Gas Utility data shown prior to May 2001 is presented for informational purposes only. The Gas Wlity business was acquired on May 31, 2001.

(3) In conjunction 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 2002. Amounts for years prior to 1999 are not available.

74 2004 annual report ii

4,129 4,047 3,902 3,657 3,642 3,634 3,519 509 452 272 107 3

2 S

4,638 4,499 4,174 3,764 3,645 3,636 3,519 427 434 412 405.

312 406 390 41 49 31 12 (3) 468 483 443 417 309 406 390 468 483 443 417 309 406 390 2.99 3.00 2.83 2.79 2.15 2.80 2.67

.28

.33

.22

.09

(.02) 3.27 3.33 3.05 2.88 2.13 2.80 2.67 3.27 3.33 3.05 2.88 2.13 2.80 2.67 52,611 55,871 55,286 50,983 48,815 49,298 46,494 2,110 2,089 2,068 2,051 2,025 2,002 1,980 945 866 850 941 895 730 667 1,235 1,220 1,206 1,193 1,183 1,173 1,155 8,081 7,853 13,350 13,021 4,039 4,091 4,323 3,914 3,894 3,884 3,951 4,009 3,909 3,698 3,706 3,588 3,763 3,706 2.06 2.06 2.06 2.06k 2.06 2.06

.2.06 143 145 145 145 145 145 146 28.14 26.75 25.49 24.51 23.69 23.62 22.89 41.25 44.69 49.25 34.75 37.25 34.88 30.25 28.44 31.06 33.50 26.13 27.63 25.75

'.24.25 38.94 31.63 43.06 34.69 32.38 34.50 26.13 S

1,015 1,084 834 905 1,079 913 923 749 739 589 484 531 454 366 9,144 8,886 8,781 8,732 8,526 8,340 8,494 2004 annual report 75

words our industry uses Coke and Coke Battery Raw coal is heated to high temperatures in ovens to drive off impurities, leaving a carbon residue called coke. Coke is combined with iron ore to create a high metallic iron that is used to produce steel. A series of coke ovens configured in a module is referred to as a battery.

Customer Choice

_The customer choice programs are statewide initiatives giving t

customers in Michigan the option to choose alternative suppliers for electricity and gas.

Gas Cost Recovery (GCR) Mechanism A GCR mechanism authorized by the MPSC permitting MichCon to pass the cost of natural gas to its customers.

MPSC The Michigan Public Service Commision regulates the state's energy, telecommunications and transportation services industries.

Section 29 Tax Credits Tax credits authorized under Section 29 of the Internal Revenue Code, designed to stimulate investment in and development of alternative fuel sources. The amount of a Section 29 tax credit can vary each year as determined by the Internal Revenue Service.

Securitization Detroit Edison financed specific stranded costs at lower interest rates through the sale of rate reduction bonds by a wholly owned special purpose entity, the Detroit Edison Securitization Funding LLC.

Stranded Costs Costs incurred by utilities in order to serve customers in a regulated environment that absent special regulatory approval would not otherwise expect to be recoverable if customers switch to alternative suppliers of electricity and gas.

Synfuel The fuel produced through a process involving chemically modifying and binding particles of coal. Synfuels are used for power generation and coke production. Synfuel production generates Section 29 tax credits.

I Power Supply Cost Recovery (PSCR) Mechanism A PSCR mechanism authorized by the MPSC that allows Detroit Edison to recover through rates its fuel, fuel-related and purchased power expenses. The clause was suspended under Michigan's restructuring legislation (signed into law June 5, 2000),

which lowered and froze electric customer rates. The clause was reinstated by the MPSC effective January 1, 2004.

76 2004 annual report 11

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No POSTAGEl BUSINESS REPLY MAIL FIRST-CLASS MAIL PERMIT NO. 61 DETROIT Ml POSTAGE WILL BE PAID BYTHE ADDRESSEE NECESSARY IF MAILED

IN THE

UNITED STATES ATTNWRITING RESOURCES 1571 WCB DTE ENERGY 2000 2ND AVE.

DETROIT Ml 48226-9886 Ii tttlliilmnliliiliiilltililgiliiltliiliilliiliiill

overview DTE Energy's common stock is listed on the New York Stock Exchange and the Chicago Stock Exchange (symbol DTE).

The following table indicates the reported high and low sale prices on the New York Stock Exchange Composite Tape for DTE Energy common stock, and dividends paid per share for each quarterly period during the past two years:

Calendar Quarter High Low PerShare 2004 First

$ 42.29 37.92

$ 0.515 Second 41.58 37.88 0.515 Third 42.21 39.31 0.515 Fourth 45.49 41.44 0.515 2003 First

$ 49.50 S 38.51

$ 0.515 Second 44.95 38.52 0.515 Third 38.98 34.00 0.515 Fourth 39.76 35.12 0.515 As of Dec. 31, 2004, 174,209,034 shares of the company's common stock were outstanding. These shares were held by a total of 99,832 shareholders of record.

distribution of ownership of DTE Energy common stock as of Dec. 31, 2004:

form 10-K We will provide, without charge to shareholders, copies of our Form 10-K filed with the Securities and Exchange Commission. Written requests should be directed to:

Susan M. Beale Vice President and Corporate Secretary DTE Energy, 2000 Second Ave.

Detroit, MI 48226-1279 or dteenergy.com/investors officer certifications In 2004, our chief executive officer (CEO) submitted to the New York Stock Exchange (NYSE) the annual CEO certification regarding DTE Energy's compliance with the NYSE's corporate governance listing standards, stating that he was not aware of any violation to the NYSE corporate governance listing standards.

Our CEO made his annual certification to the NYSE as of May 27, 2004. In addition, we have filed as exhibits to 1

the Annual Report on Form 10-K with' the Securities and Exchange Commission, the certifications required under Section 302 of the Sarbanes-Oxley Act of 2002 regarding the quality of the company's public disclosures in the fiscal year-end 2004 reports.

Type of Owner Owners Shares Individuals 40,889 12,636,138 Joint Accounts 37,363 15,385,259 Trust Accounts 1,468 1,047,942 Nominees 38 136,597,601 Institutons/Foundations 40 40,651 Brokers/Security Dealers 46 30,529 Others 19,988 8,469,914 Total 99,832 174,209,034 State and Country Owners Shares Michigan 51,494 20,538,997 Florida 5,941 2,653,067 California 4,903 1,703,692 New York 3,908 137,904,170 Illinois 3,765 1,380,697 Ohio 3,111 1,029,857 44 other states 26,300 8,865,125 Foreign countries 410 133,429 Total 99,832 174,209,034 transfer agent The Bank of New York Send certificates for transfer and address changes to:

Receive and Deliver Department, P.O. Box 11002 Church Street Station, New York, NY 10286 Telephone: 866.388.8558 www.stockbny.com registrar of stock and other information

Address shareholder inquiries to:

The Bank of New York, Shareholder Relations Department P.O. Box 11258, Church Street Station, New York, NY 10286 or e-mail inquires to: shareowners@bankofny.com As a service to shareholders of record, DTE Energy offers direct deposit of dividend payments through The Bank of New York.

Payments can be electronically transferred directly to the bank or savings and loan account of choice on the payment date.

Write to the address above, or call 866.388.8558 to request a Direct Deposit Authorization Form.

Shareholders of record can elect to receive future copies of our Annual Report and Proxy Statement electronically by marking the appropriate box on their proxy card as instructed.

By electing electronic delivery, you are stating that you currently have or expect to have access to the Internet.

annual meeting of shareholders The 2005 Annual Meeting of DTE Energy Shareholders will be held Thursday, April 28, 2005, at 10 a.m. (EST) in the DTE Energy Building, 660 Plaza Drive, Detroit, MI.

corporate address DTE Energy, 2000 Second Ave.

Detroit, MI 48226-1279 Telephone: 313.235.4000 dteenergy.com independent registered public accounting firm Deloitte & Touche LLP 600 Renaissance Center, Suite 900 Detroit, MI 48243-1704 T

2005 D

rTE TE Energy Company, I

I all 1rights reserved.

NYSE DITE Energy is the owner of the THead'Corona" logo. DTE Energy or its affiliates are the owners of various other registered and unregistered trademarks.

Printed by St Ives Inc Miami, Fla, 2004 annual report 77

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