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 ,-kbD -

A I)TE Energ Company

- am 2004 annual report

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iairman's letter ility businesses in-utility businesses

)ard of directors

,ecutive committee tief financial officer's letter,,,:..

anagement's discussion and analysis'.--,

eport of management's , .p .p.

responsibility

- n =.iblt 3ports of independent registered iblic accounting firm nancial statements ",

otes to consolidated financial statements

-year statistical review

/ords our industry uses Flier information about DTE Energy- 5 --- -

2004 annual report 1

iI 2 2004 annual report

.1

<DTE nrgy imp~~~1 ATO~-L-NA4.si

,icr . renera. - eneral Z-lin, , i-M pnt, one cler pI t.;nu

.I W pnpr ria k;hin, m 'in

-f 2004 annual report 3

I !0215FI.. a .~ agI.,. 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 jI 11I Electric Utility S

$ -150 i 1 $ 252 (40.5) %/

I %

Gas Utility E-;`20 29 (31.0)

Non-utility Corporate & Other r I ~

t:-

283

- (10) i

,fi 256 (57) 10.5 N/A 443 -! 480 (7.7)

Discontinued Operations (12) -1 68 (117.6)

Cumulative Effect of Accounting Changes . - ~i (27) 1$ - 431 I $ 521 (17.3) .%

i~ .`iI ,

Diluted Earnings Per Share Electric Utility 0.87 $ 1.50 (42.0)

Gas Utility ; 0.11 0.17 (35.3)

Non-utility 11.63 1.52 7.2 Corporate & Other (0.06) (0.34) *(82.4) s - 2.55 - 2.85 (10.5) %

Discontinued Operations f (0.06) - 0.40 (115.0) %

Cumulative Effect of Accounting Changes I X - (0.16) t $ - 2.49 . $ 3.09 (19.4) %

Dividends Declared Per Share $ 2.06 $ 2.06 Dividend Yield -4.8 % 5.2 % 1 (8.6)

Average Common Shares Outstanding (Millions)

Basic 173 168 ! 3.0 Diluted 173 i 168 i 3.0 Book Value Per Share $ 31.85 $ 31.36 1.6 Market Price at Year End $ 43.13 ' $ 39.40 ' 9.5 Total Market Capitalization $ 7,514 $ 6,643 i 13.1 Investments and Capital Expenditures $ 940 $ 785 . 19.7 Total Assets $ 21,297 $ 20,753 , 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.

. I _. , ' " - I__' 'r '.

L U DTE Energy X 61" 11_ "-.-- ,

" - _2-,-_ i- 11 - . ,, . . 7 7- . -~ 175% 1 01 S&P Electric Index Source: CompuStat L6i fl I

.z.

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 4 2004 annual report

We faced enormous challenges in 2004. -Fortunately

.y.ea^ en _r ;f p e se wi,_;.:Xr.

t....ii~^

, #*s oL

. . year end most were behind us. 'I'm pleased with by 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

-and 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 assare, 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.- -

'-1 4 I *. -

- -. - - - 4 *4'

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

:back at 2004.;.Addressing regulatory concerns-;-s s 1-2

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

- *4 - 4

- 't.

4 4

44 4

'4

.';? ;Public'Service Commission (MPSC) issued a final 4- 4 4 44 order on our electric rate case It was the first rate

a track rec increase in 10 years for our electric subsdiary

-DetroitEdison and among the most complex in

'.'- higi.. historyig We received a $74 4 .4 4 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.

fe-'- '4. c.. ,. ;

2004 annual report 5

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

--directionally 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

__'Management's Discussion f o reta).-

gh 3 ccase fied by our natural gas rate subsidiary MichConiswas alSo the irstin

a. deade.'-WNVexpect to receive a final *.-.* '

ra er in the irst quaer of 2005.

Becaus e -, ;.order will beissued late in l~t -:f or

.6 - i; qlat, i=n.,

E_*. 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' more than 90 percent of our capacity, with plans to sell at least an aidditoiona 7 percnt 6 2004 annual report

.'$ 65 -I s id achie; d as Iur We expect to generate'approinmately $1.65 billion' leverage to'48 percent and achieved our cash-e c frof m sfl b 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 t sh should hat help position'our company our success in 2005:

for long-teirm griowth.(Reaid more about this -'

'- . -..n sucess fr in 2 5

.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 ' ; - progress.:.-Last month we complied with made --.-- x Enteringthepp paperindustryrte t hto

- = t;^t electricity serviersto attisu ml Aabaa. resOgoli to'restuctr rtes estabhin

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

-,',:Ex-,,KEpa'nding'our unc~onventional ga sproduction ' -.- tht-"artificially sk' th classes................ - M-......................

,, ~-tr fo

-,hgal shale in. -- -- na.:4RC-..-

d rilling

-~-, >.n.faong srate clse tht Itlllyse h ::~,'.-

tetwlsi the Bantsae nTxs - copeitiv environment.;,.-

-. ontnigslidpromnefrom fuel - ---

.tranportation and marketi g businesse fs

,,,..,...,i,., .- .e our-uture Lcss io ' esrthe

..;,-Our fourth 2004 priority'was to maintain cash - p s al.ows timely'recovery of our dbale ia t trength. We loeedour p ens. ve men-.;

2004 annual report 7

7 ;.Our'second priority, is to de reduce costs. '.We are developing a culture that regulatory strategythat'not ;'-t@'t'- -, uses this approach on the job every day to boost . j'- -.--- ':;

current'rate cases,:but antie peformance and productivt. In 2004, we investments in our'system.ui realized savings of approximately $105 million' ii value,,;,- through variousOperatingiSystemi ovemets

-eOur

' third priorityis toict - e'veraised the bar 'even hi for 2005 creation This involves inve rony '-'.' '44~ . -4~a. 4 ---

.- "-4.- <

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

- _ -44S'

.Weexect net income from

'.:d u

.otc _ er,4nt-shd-v e to'increase appr rcent=. =

-in 2005. also are develo r masve,,tt redunansv fot-treplace our outdated and r- 4 w-\t-

-';-pursuinfg the business wee

',-4' 'eudn in~form'ation teholg sytm.'4-

'..'Choice over the'past fewi ye As we phase in our new computer system and

inewbusiness

..-:Fw.-

__>L,_-.~c .ow opportunities weusreA

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

i

- '--4, IN . We-do not,-however, intend: finance',' supplychain' humansresourcesand

='.'exene'f urb'alance'she, citted operations. .When this project is complete,' . ,

a < sterg,strong maintaining finani pera* eand 'i... we'expect

> ~; ~ ~ ~ steady ~ ~ state.4annual.- savings of - -'

I

' ':tto S e - -4 4

':balance sheet strength-. oi ?...'j' .e-.j

$"75 f, mfillion'i'

million toj,+$100 annual .' sa-vings o

, Fib:meet our targets for eari and Our final priority is to-build an engaged work

.Scash flow, we must remain~ iging -force with the commitment and skills needed 4.-sl;t,°v S

.>.costs. Our fifth priority,, prx iiev ^'-todriveDTE Energys suiccess -This'is a broadW.

tL-'4i, operational excellence-41 this target that starts with an intense'focus on safety

. 'focus. -As we improve the'v ss, It iiiiolves training and developing our employees .. ..u~f-

-,~j~-ofinancial performianc n to'ensurewe have the'right mix of skills and tl r theool ofuuleader also involves b x.pertio in 3 x:-,.streamline processes, elimi j4 .4 i 4 ' -'4'3o

,4-4 9tz - - <*Q,. , .7 ', , j,;

-4 8 2004 annual report

'; r 't srecrueitin

= .. t' za---_ad pttial

', = ', ,

developing i w

. .--=..--,candidates, givng them opportunities ' rIi.

- L,'.-succession plans.

presde W E S-ob~d-V-k-o-f aXL' <"; 'GAII Tvi r_ry Ai -d1 a;t

.. I was yery pleasedto announce- list year l;.-theappointment of GerryAnderson as- '4~EnergydentK^,,,,* 1Y Ij 2.K'

president of DTE Energy hGerry hase; Ger Anderson -. 66+. : --- ;

-=-.x-

,served for the past six years'as'a-group :9i v1..

.'..president oversexeingour electricfpoWer'..--- Iur pl'rabfo rneivesting casnh

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

., -i, Q, ohaveav' trat6irintoan iriverh i=Weex^ectour non-utility bisines§ use-'Ž to genee $2 bilion in hf o the

-A- 1' . wil provide a unique orbtunity to build our compans t~~f _W .'inte'.;>A5>'t .i > ;ve i f '-4 hi 'hSXt'fl tX tes rspnibilities,'in his'new role he ,a-, , - -

,.f,,:, 'value and s ape- its

-A . .

future.

We'intend to invst $350 million of this cash flow as l _. ..-

i~l aso prov&ides executive leadership for :-^--.iB.'---equity in Detroit Edison to help fund ouir cean air investments' This leaves,

-overall

'i sttategic planning and other ~'-.' $1.65 billion to redeploy in other wiays. - t -'.

A t; -i h e - - la - s;

'1.,..e'critical initiatives." -Z,, ,d; ,>5-'.<

Ourprimar objeictives in redeploying this cas are to

-r~ 3/4 - -,' ' ai Shape our balance sheet to meet both our near-term and long term 2 .- Gerrj and I arecoinmitted to deliverring S'f cr-e'.credit objectives.. , . -:.-f, the type of value you have come tot ;:

' Repiace and'exceed the value' of s cash flow'currently inherent in expect from'DTE Energy On behalf off-' our stock price.

all our'employees thank you for your We expect to achieve these objectives by:. ' .

,' 'continu'ed support ,- .i .,,., - -. '..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 to $900 million of capital into non-utility businesses -

i-$600hillhion f6m2005-2008 at attractive returns. ' - . ' -

Repufrchasing shares to help build vaiue6 tothe degree that adequate :

-Anthon alyJ Caraad Chie Eeu investment opportunities -are not available." ' -

tie er.70i-len- i--oivet-u March120 - It s anincredibly citin ti e for TE Ene O allene is toistour

, ,-4 ., ; d;. A ;- . , '

-cashwisely 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 batteryoperation, Gary, d. -- - ' - -- ' ' '

2004 annual report 9

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

e,' , " and cont - to mee

'pin 'Otue and et cd theeetatons

a * > 'At the same time we gro ou c be'

^S '

wemsshrik t csts. The DTE EnergyOperatig 1-:L:. tA..- * * ~ se is a powerful tool wersn t ojs that. I's a sta rt t b

.~~W were te-...:l ,din200, .,st whe 4focsdo reducing waste, imj.................processes..

hampered ou growth. remained focused, lButwe Littlments CA nce iion reaning the health f our duteiliti Det ro prges eds In Aardmd 205 ccrigt fixes t ransfres BbBune ithea neetrca Warren Servi Centeh DtotE onand Michion wlcotueo electric al shop. .Because o h hne ev their financial ist d pLositi6n' r, u e er gh s, forfutregrowtlong em;'we Ivthemelves Icontrolmyowndestiny"

. expect s 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` ableaa, 4

Mgr~ichelyuse t heuines 4

o we'vem lostl uinad aae temo en Fempaoyeesused Operating tem tools to study P seek new busi ess

- .rcs.

PI eydiscovered each transformer' K* Continue to reduce ctstthrourv five miles withinthe facility during jf operatingefficienciesrepair e proactiv in ma and, once ixe days g oo d

regulatory process -.-

10 2004 annual report 11

71771U 2004 annual report 11

- I. -1 - - . .. . 11--.1 -1.1 - - - - . I.- . - I I --.[Po

--Armed with this knwegteta reated stan dard orkins i bisrepairs me u n_ thet' company an estimated $500,000 hi the

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

inn-,are now comnpleted injust eight hours.

_~ ir I Co!mbined 'ith other Operating System 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 iy`,sTe sayis powe~~rp.. umio s wJoh;tthatthe Operating.:i,.

Ssea~a business opportunity -aind took bierviti inta e'te1 enter;-e tftf1

_ an you kow what? Most eo ple 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 peratmg System,71 tEhe plant-completed its last outage in 27 days, t beating its_ prei is recor by an in3pressive six days -Clearly, using tools'of the Operating,~

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

12cost effectively and inrrecorrd time aBl v president of nuclear generation.

I r

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

saeybognition, the Michigan Volunty 12 2004 annual report

q Employees at the Broadway Station,-a MichCon - )TE Energy Operating System is

-facility used the Operating System to substantially -f ;ernally, we're focused'externally on

.increase their productnty. With the lowest field ,-, he regulatory environment for our service productivity of all our Detroit area service t' urfgoal is to establish a multi-year

'-' centers, the Broadway Station assessed, analyzed r trategy that addresses currenit and improved the situation byimplementing c and ticipates future~ne'edsb'ased..',;

. tools of the Operating System. 'Going from worst nging marketplace. e . ,-.,,.;

- to first m performance, todaythe Broadway tterm, we'll continue to build stable .

-' Station isnumnber one in productivityi.-

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

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

I'11 ill .'

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

oti

,'i., d y impact the performance of our Cost savings and increased productivity arejust rm of Elecrc Choice'!,. ,,/o two of the benefits of the Operating System.

It's also'helping us income energy assistance indhng and restructuring electric rates.'.> ,

'S~~t ~ -. ",.:Redu'ce injuries. ;-w'--W..';-fE

Reduc'e'absenteeiSM ironmental controls and cost recovery.

Reduce power plant emissions gfewyeals rising health care'osts,-

Speed up the hiring process. ure costs, bad debt expense and sfro'm Electric Choice outstripped-. -;

e Improve customer restoration times.'

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

Reduce customer complaints. tion of;,our 6fetr electric and natural gas . L.' -

_--e

gol is'to'moveb roit Were, .rproud of our successesi'but recognize there

)

=,,f,,W i..o-udf .. U> 9 i - ,,b, ichCon to their authorized',0 .

_ -arestill many opportunities to improve. In 2005,,

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

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

aullding for our utilities, zwitl* a return - ;

into our organization with a goal i identify

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

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

2004 annual report 13

.investing fr gro" 'th Our strategy is to grow in areas closely linked:

to our utlteboth in the type of business 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 isthe second largest operator of Antrimi gas jI- 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,:

tsjutone exampl ouor growth strategy for of one of the lowest cost operators in the state.

non-utility businesses. Our investments follow:- When we evauate potentialinvestm-entswe look A;-

two broad approaches: -

for a fit in'on~e ofthree areas: -;

Power and industrial projects, such as

Niche businesses'with limited competition

o-n-site energy and steel-related projecs and strong returns,,such as arettsae power generation and waste coal recovery; svnfuel production, industrial coke and

Ucnventionlga rduction, such as waste coalrecovery--

shale and landfill gas production;

Lower risk businesses where we can add value, such as on-sit energy poet *Fuel transportation and marketing, such as that leverageour operto sad coal services, gas pipelines and storage, and;!

maniagement experience. e6nergy mnarketing a dtaig We focus on valu. Nosie and scope. B We have an impressiv'e track record linthese :.

realnig true to, this ph-ilosophy, our non-utilit areas, particularly with on-site energy services.

i businfes~ses9 grew substantiallyfoth eigt We operate 19 major sites for heavy energy users i consecutive year. And we exetnticm in-the automotive, ste-el, pulp and paper, and from these~b~usinesses toincr~ease app.roximately- commercial and institutional- sectors& This 30 percent in 2005 includes nine sites added to our portfolio in 2004.1 I

14 2004 annual report Ii

'terriory I3/4 I

2004 annual report 15

One' 'ofour 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:. g:.:

-7.;;

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 oUr expertise around coal, we began operating our first waste coal reco'very plant "in2004. Using proprietary,:E technology we're turning coal slurry fron waste ponds into a quality of coal almsts --

g~oodas that produced from the original',-

16 2004 annual report

- v - 2 s R

' --- mine. We're refining this process, and believe pansion of Vector is likely,'as is--

there's great potential in this untapped market. of our Michigan storage fields.-

L:veraging our knowledge and experience in percent of the proposed power plant operations, in 2004 we began line that will run from western providing services to financial institutions that. vYork City. We-view Millennium control distressed power generation assets. hide to move gas out of storage into markets in New York City We currently manage and operate two plants, the Northeast.

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

' 'produce1,800 MW of electricity. 'We have no

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

- servce we provide. -

- 7, L' Our'strong reputation in delivering on-site I services, combined with our expertise in coal, I _I is leading to other opportunities in power ears present incredible ortunities across our portfolio generation. 'For example, we're developing -

isinesses, thanks to the excess a 200-MW coal-fired power plant for an-

from our synfuel businesses.:-

international mining company with operations this in the Chairman's letter.)

in the western U.S. We will look for similar plan to continue following our ventures with other companies.

management strategy. We do Our existing gas pipelines and storage business' row at the expense of our balance also offers growth potential. -We own'40 percent Ian to seek quality investments

-of the Vector pipeline, a 348-mile interstate it exceed our cost of capital.- 0 pipeline supplying natural gas from Chicago to,: focus on opportunities closely Dawn, Ontario. The pipeline, which is operating ore businesses.

at fill capacity, runs through the heart of ght years, we have built an MichCon's service territory and gas storagee ecord of successful investments.

fields. Because demand in the region is very 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 schirmn, 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 exctvie presidentEof . Anderson joined th erTE 193 rm oinsey &Wterhe was a consultant inen(

DvdE Mar, iexcutiv viepeident adche

.(F) ejie T Eeg n19 svc president arid con e~cesenj si~anCOi 01. In2004 e a currntosiior~lna~1i iti~l~ eador served as si

-w o lfiiiarci& an ccutnpoiosatCrysler Corp. for14 yea

- a~idit~ir i-Coopers nd

'Susan MBal56iviepeintand o

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

~-secretaiy in1989'6and as lctdvieprsdetHe in99.'She cameto'DTI.Efnergyahferfouyar oit wihIh lgal staff of Southern CaliforniaEio ad two ears w ithnsumersi Powier RoerBuker, 55 sgoppeieto IJTE Energy 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 a7~~ 9r aic~ 14y Steplhen E.Ein 60 isgou rsietof 5 DTE Energy Gas. Hjondte compn in201from MCN Energy ,Werekhe'sierve as ~Jie ispresident an c- corpo president~dcife c fe'b ceerif n.,joinedc and Michi

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

2004 annual report 19

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

'I believe we have tumned the cormer. With our electric and natural.I .Likewise, our financial objectives have remained constant:

'gas rate cases behind us,we expect the financial health of our two -Focus onvalue creation (achieve returns that exceed our cost of capital).'

utilities to improve considerably in 2005. We anticipate cash flows

Maintain a strong balan'ce sheet and solid investment will improve dramatically, providing significant financial flexibility.

grade rating.

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

-SGenerate future earnings growth.:

You've already read about our opportunity to reinvest approxinately ' Maintain our dividend at $2.06 per share while our utilities

$1.65 billion in cash, expected prirn from synfiuel over the next .. improve their health.

-four years. Included in the total is an additional $400 million from

Continue to communicate openlyand transparently about our performance.

growth of our other non-utility businesses. -

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

-As we evaluate our options for redeploying this cash, we will seek

-performancefor our shareholders over the last five and investments that create value and are consistent with our strategy. . was 2004, when .uncertainty surrounding 10 years.

10 The Th; exception .er. 004 .d . W

'At the same time, we will remain disciplined. We plan to build Detroit Edison's electric rate case slowed our momentum.

on our company's unique strengths and pursue closely related

. Despite this challenge, we maintained the growth of our businesslines.- .; ~~

- . ~ ,-.* ~ ~ ,t-. dr .- .-

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

Our plans include investing where the competition is manageable, I am deeply committed to achieving our financial objectives.:

while focusing on cash flow first, scale second. 'The obje is

-I do not intend to let you down.'

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. :-=- . David E Meador Execufive Vice President and Chief Financial Oflicer -

We 'areproud 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 restructuring proposal in February 2005 designed to adjust rates DTE Energy is a diversified energy company with approximately for each customer class to be reflective of the full costs incurred

$7billion in revenues in 2004 and approximately $21 billion in to service such customers. Under the proposal, Detroit Edison's assets at December 31, 2004. We are the parent company of commercial and industrial rates would be lowered in 2006, but Detroit Edison and MichCon, regulated electric and gas utilities residential rates would increase over a five-year period beginning engaged primarily in the business of providing electricity in 2007. The number and mix of and natural gas sales and distribution services throughout 7 customers participating in the electric southeastern Michigan. Additionally, we have numerous Customer Choice program could be non-utility subsidiaries involved in energy-related businesses impacted under the rate restructuring.

predominantly in the Midwest and eastern U.S. Lost margins and electricity volumes a A significant portion of our earnings is derived from our utility associated with electric Customer operations, synthetic fuel business, and energy marketing and Choice were approximately $237 million trading operations. Earnings in 2004 were $431 million, or and 9,245 gigawatthours (gWh) in

$2.49 per diluted share, down from 2003 earnings of $521 million, 2004. This compares with lost electric or $3.09 per diluted share. As discussed in the "RESULTS OF Customer Choice margins and volumes OPERATIONS" section that follows, the comparability of earnings of approximately $120 million and was impacted by discontinued businesses and the adoption of 6,193 gWh in 2003. The financial impact new accounting rules. Excluding discontinued operations and the of electric Customer Choice was affected cumulative effect of accounting changes, earnings from continuing by the issuance of electric interim and final rate orders operations in 2004 were $443 million, or $2.55 per diluted share, that increased base rates, authorized transition charges and compared to earnings of $480 million, or $2.85 per diluted share reaffirmed the resumption of the Power Supply Cost Recovery for the same 2003 period. Income reflects reduced contributions (PSCR) mechanism, as subsequently discussed. Partially from our utility operations, partially offset by increased contribu- offsetting the impact of lost margins on income, we recorded tions from our non-utility businesses and Corporate & Other. regulatory assets representing stranded costs that we believe are Significant items that influenced our 2004 financial performance recoverable under existing Michigan legislation and MPSC orders.

and/or may affect future results are: There are a number of variables and estimates that impact the level of recoverable stranded costs, including weather, sales mix

Electric Customer Choice penetration; and transition charges. As a result, our estimate of stranded costs

Electric and gas rate orders; could increase or decrease. As subsequently discussed, the MPSC

Higher operating costs; authorized the recovery of $44 million in stranded costs for the

Weather; period of January 2002 through February 2004.

Synfuel-related earnings and the risk of higher oil prices; and Detroit Edison rate orders, along with the rate restructuring proposal, address certain issues with the electric Customer Choice

Growth of non-utility businesses. program. However, current regulation continues to hinder our ability Electric Customer Choice Program- Since 2002, Michigan to retain certain customers. Accordingly, we will continue working residents and businesses have had the option of participating with the MPSC and Michigan legislature to address other issues in the electric Customer Choice program. This program is associated with the electric Customer Choice program.

designed to give all customers added choices and the opportunity Electric Rate Orders- In 2000, Public Act (PA) 141 froze to benefit from lower power costs resulting from competition. electric rates for all residential, commercial and industrial However, Detroit Edison's rates are regulated by the Michigan customers through 2003. The legislation also prevented rate Public Service Commission (MPSC), while alternative suppliers increases (or capped rates) for small commercial and industrial can charge market-based rates. This regulation has hindered customers through 2004 and for residential customers through Detroit Edison's ability to retain customers. In addition, the 2005. The rate freeze and caps apply to base rates as well as MPSC has maintained regulated rates for certain groups of rates designed to recover fuel and purchased power costs which customers that exceed the cost of service to those customers. has traditionally been a cost pass-through under the Power This has resulted in high levels of participation in the electric Supply Cost Recovery (PSCR) mechanism.

Customer Choice program by those customers that have the highest rates relative to their cost of service, primarily commercial In 2004, the MPSC issued interim and final rate orders that authorized electric rate increases totaling $374 million, and and industrial businesses. As a result, our margins continue to be affected. To address this issue, we filed a revenue neutral rate eliminated transition credits and implemented transition 2004 annual report 21

charges for electric Customer Choice customers. The increases were the MPSC in February 2005 seeking authority to implement a applicable to all customers not subject to a rate cap. The interim tracking mechanism for retiree health care costs.

order affirmed the resumption of the PSCR mechanism for both Both utilities continue to experience high levels of past due receiv-capped and uncapped customers, which reduced PSCR revenues ables, especially within our Energy Gas operations. The increase by $115 million in 2004. However, the order allowed Detroit Edison is attributable to economic conditions, high natural gas prices and to increase base rates for customers still subject to a cap in an the lack of adequate levels of assistance for low-income customers.

equal and offsetting amount to the change in the PSCR factor to As a result of these factors, our allowance for doubtful accounts maintain the total capped rate levels in effect for these customers. expense for the two utilities increased to $105 million in 2004 The MPSC also authorized the recovery of approximately $385 compared to $76 million for the corresponding 2003 period. We are million in regulatory assets, including stranded costs. taking aggressive actions to reduce the level of past due receivables, As a result of rate caps, regulatory asset adjustments and other including customer disconnections, contracting with collection factors, the rate orders decreased 2004 earnings by $15 million. agencies and working with the State of Michigan and others to The impact of the rate orders is expected to increase earnings increase the share of low-income funding allocated to our customers.

in 2005 and 2006 as rate caps expire. In MichCon's current gas rate filing, we addressed numerous Effect of Interim and Final Rate Orders operating cost issues, including uncollectible accounts receivable (inMillions) 2004 expense. The MPSC Staff supports a provision proposed by MichCon Base Rate Increase and Transition Charges $ 154 that would allow MichCon to recover or refund 90% of uncollectible PSCR Reduction (11 5 accounts receivable expense above or below the amount that is reflected in base rates. We support the MPSC Staff's recommenda-Regulatory Assets tion and believe the provision would significantly reduce our risk of Stranded costs adjustment (33)'

high uncollectible gas accounts receivable.

Regulatory asset deferrals - cessation (1) (29)

Pre-Tax Income (Decrease) $ (23)1 To partially address this issue of rising costs, we continue to employ Net Income (Decrease) $: (15) the DTE Energy Operating System, which is the application of tools and practices to obtain operating efficiencies and enhance operat-(1)We ceased recording regulatory assets for costs that are reflected inrates ing performance. We are targeting over $100 million in savings pursuant to the MPSCs 2004 rate orders. during 2005 through the application of Operating System principles.

See Note 4 for a further discussion of the MPSC's interim and Weather - Earnings in our electric and gas utilities are seasonal final rate orders. and sensitive to weather. Electric utility earnings are dependent Gas InterimRate Order - In September 2003, MichCon filed on hot summer weather, while the gas utility's results are driven an application with the MPSC for an increase in service and by cold winter weather. We experienced both milder summer distribution charges (base rates) for its gas sales and trans- and winter weather during 2004, which negatively impacted sales portation customers. The filing requested an overall increase in demand. The lower demand reduced current year earnings by base rates of $194 million annually (approximately 7%increase, $27 million compared to 2003.

inclusive of gas costs), beginning January 1,2005. In September Additionally, we occasionally experience various types of storms 2004, MichCon received an interim order in this rate case that damage our electric distribution infrastructure resulting authorizing an increase in base rates of $35 million annually, in power outages. The impact of storms on our current year effective September 22, 2004. The interim rate order increased earnings was significantly lower than in 2003, which was affected earnings by approximately $6million in 2004. MichCon expects by several catastrophic wind and ice storms, as well as by the a final order from the MPSC in the first quarter of 2005.

August 2003 blackout. Restoration and other costs associated OperatingCosts - During 2004, we experienced increases in with storm-related power outages lowered 2004 pretax earnings operation and maintenance costs, primarily within our electric by $48 million compared to $72 million in 2003.

and gas utilities. The increases were driven by higher costs Synthetic Fuel Operations- We operate nine synthetic associated with pension and postretirement benefits and fuel production plants at eight locations. Since 2002, we have uncollectible accounts receivable.

sold majority interests in eight of the nine plants, representing Pension and postretirement benefits expense totaled $212 approximately 92% of our total production capacity. Synfuel million in 2004, compared to $172 million in 2003. The increase facilities chemically change coal, including waste and marginal is due to financial market performance, lower discount rates and coal, into a synthetic fuel as determined under applicable increased health care trend rates. We have made modifications Internal Revenue Service (IRS) rules. Section 29 of the Internal to the pension and postretirement benefit plans to mitigate the Revenue Code provides tax credits for the production and sale earnings impact of higher costs. Additionally, the recoverability of solid synthetic fuel produced from coal. Synfuel-related tax of pension and health care benefits costs were part of our credits expire in December 2007.

electric and gas rate filings. The MPSC approved a pension Operating expenses associated with synfuel projects exceed tracking mechanism in Detroit Edison's final rate order that operating revenues and therefore generate operating losses, provides for the recovery or refunding of pension costs above which have been more than offset by the resulting Section 29 tax or below the amount reflected in base rates. The MPSC also credits. In order to recognize Section 29 tax credits, a taxpayer required Detroit Edison to propose a similar tracking mechanism must have sufficient taxable income in the year the tax credit is for retiree health care costs. Detroit Edison filed a request with generated. Once earned, the tax credits are utilized subject to 22 2004 annual report 11

certain limitations but can be carried fonvard indefinitely. Assuming no synfuel tax credit phase out in future years, we We have not had sufficient taxable income to fully utilize tax expect cash flow from our synfuel business to total approximately credits earned in prior periods. As of December 2004, we had $1.6 billion between 2005 and 2008. The source of synfuel cash

$483 million in tax credit carry-forwards. In order to optimize flow includes cash from operations, asset sales, and the utilization income and cash flow from our synfuel operations, we have sold of Section 29 tax credits carried forward from synfuel production majority interests in eight of our nine facilities and intend to sell a prior to 2004.

majority interest in the remaining plant during 2005, representing Non-utility Growth - During 2004, we continued to experience 99% of our production capacity. When we sell an interest in a growth in our non-utility businesses with income reaching synfuel project, we recognize the gain from such sale as the facility $283 million compared to $256 million in 2003. The improvement produces and sells synfuel and when there is persuasive evidence primarily reflects increased contributions in our Energy Marketing that the sales proceeds have become fixed or determinable and &Trading segment, primarily due to a one-time contract gain.

collectability is reasonably assured. Gain recognition is dependent' Additionally, non-utility growth in 2004 is attributable to increased on the synfuel production qualifying for Section 29 tax credits and earnings from our synfuels, coke batteries and on-site energy the value of such credits as subsequently discussed. In substance,,, projects. Also affecting the year over year comparison are we are receiving synfuel gains and reduced operating losses in asset gains, losses and impairments during 2004 and 2003 as exchange for tax credits associated with the projects sold. Sales of subsequently discussed.

interests in synfuel projects allow us to accelerate cash flow while Outlook - We made significant progress during the past year on maintaining a stable income base.

our 2004 corporate priorities, which included:

The value of a Section 29 tax credit can vary each year and is

Successful rate case outcomes; adjusted annually by an inflation factor as published by the IRS in' April of the following year. Additionally, the value of the tax'credit

Addressing structural issues with the electric in a given year is reduced if the "Reference Price" of oil within the Customer Choice program; year exceeds a threshold price and is eliminated entirely if the

Continuing sell-down of synfuel portfolio; Reference Price exceeds a phase-out price. The Reference Price

Continuing non-utility growth momentum; and of a barrel of oil is an estimate'of the annual average wellhead

Maintaining cash and balance sheet strength.

price per barrel for domestic crude oil, which in recent years'has Our long-term strategy has not changed and in 2005 we will been $3- $4lower than the New York Mercantile Exchange focus on maintaining a strong utility base, pursuing a unique (NYMEX) price for light, sweet crude oil. The actual or estimated growth strategy focused on value creation in targeted markets, Reference Price and beginning and ending phase-out prices per maintaining a strong balance sheet and paying an attractive barrel of oil for 2003, 2004 and 2005 are as follows: dividend. The impact of the rate orders is expected to increase Reference Beginning Ending utility earnings in 2005 and 2006 as rate caps expire.

Price Phase-Out Price Phase-Out Price Our financial performance will be dependent on successfully 2003 (actual) $27.56 $50.14 $62.94 redeploying an expected $1.65 billion of cash flow through 2008, 2004 (estimated) $37.61 $51.34 $64.45 primarily associated with proceeds from the sale of interests in 2005(estimated) NotAvailable $52.37 $65.74 synfuel facilities. Our objective for cash redeployment is to Numerous recent events have significantly increased domestic strengthen the balance sheet and coverage ratios, as well as crude oil prices, including terrorism, storm-related supply disrup- replace the value of synfuels that is currently inherent in our tions and strong worldwide demand. As of February 1,2005, the share price. We will first use our cash to reduce parent company NYMEX closing price of a barrel of oil to be delivered in March debt. Secondly, we will continue to pursue growth investments 2005 was $47.12, which is comparable to a $43.47 Reference Price that meet our strict risk-return and value creation criteria.

(assuming that such price was to continue for an entire year). Lastly, share repurchases will be used to build share value For 2005 and later years, if the Reference Price falls within or if adequate investment opportunities are not available.

exceeds the phase-out range, the availability of tax credits in RESULTS OF OPERATIONS that year would be reduced or eliminated, respectively.

We had earnings of $431 million in 2004, or $2.49 per diluted As previously discussed, until the gain recognition criteria is met, share, compared to earnings of $521 million, or $3.09 per diluted gains from selling interests in synfuel facilities will be deferred. share in 2003 and earnings of $632 million, or $3.83 per diluted It is possible that gains will be deferred in the first, second and/or share in 2002.-As subsequently discussed, the comparability of third quarters of each year until there is persuasive evidence that earnings was impacted by our two discontinued businesses, no tax credit phase out will occur for the applicable calendar year. International Transmission Company and Southern Missouri Gas This could result in shifting earnings from earlier quarters to later Company, and the adoption of two new accounting rules in 2003.

quarters of a calendar year. - Excluding discontinued operations and the cumulative effect of As discussed in Notes 12 and 13, we have entered into derivative and accounting changes, our earnings from continuing operations in other contracts to economically hedge approximately 65% of our 2005 2004 were $443 million, or $2.55 per diluted share, compared to synfuel cash flow exposure related to the risk of an increase in oil earnings of $480 million, or $2.85 per diluted share in 2003 and prices. We are continuing to evaluate the current volatility in oil earnings of $586 million, or $3.55 per diluted share in 2002. The prices and alternatives available to mitigate our unhedged exposure following sections provide a detailed discussion of our segments, to oil prices as part of our synfuel-related risk management strategy. operating performance and future outlook.

2004 annual report 23

Segment Performance& Outlook - Through 2004, we operated (inMillions) 2004 2003 2002 our businesses through three strategic business units (Energy Operating Revenues S 2,210 3-?$ 2,448 $ 2,711 Resources, Energy Distribution and Energy Gas). Each business Fuel and Purchased Power 868 i X 920 1,048 unit had utility and non-utility operations. The balance of our Gross Margin 1,342 1,528 1,663 business consisted of Corporate &Other. This resulted in the Operation and Maintenance 672 628 626 following reportable segments. In 2005, we expect to realign Depreciation and Amortization 27 224 331 our business units as discussed in Note 1. TaxesOtherThan Income -147 157 156 (inMillions, exceptper share data) 2004 2003 2002 Operating Income 251 519 550 Net Income (Loss) -- Other (Income) and Deductions -166' 149 189 Energy Resources Income Tax Provision 23 135 120 Utility- Power Generation S 62, $ 235 $ 241 Net Income $ 62 $ 235 $ 241 Non-utility -

Energy Services vi 188 j 199 182 Operating Income as a =

Energy Marketing &Trading .. 92; 45 25 Percent of Operating Revenues * - 11 % 21 % 20 %

Other :., (2) 7 Total Non-utility 281 242 214 Gross margin declined $186 million during 2004 and $135 million 343 477 455 in 2003. The declines were due primarily to lost margins from retail Energy Distribution customers choosing to purchase power from alternative suppliers Utility - Power Distribution 88 17 111 under the electric Customer Choice program as well as reduced Non-utility (19) (15) (16) cooling demand resulting from mild summer weather. As a result

-69 2 95 of electric Customer Choice penetration, Detroit Edison lost 18%

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

Utility - Gas Distribution - 201 29 66 The loss of retail sales under the electric Customer Choice program Non-utility ,',21 i 29 26 also resulted in lower purchase power requirements, as well as 411, 58 92 excess power capacity that was sold in the wholesale market.

Corporate &Other . (10) (57) (56) Under the 2004 interim and final rate orders previously discussed, revenues from selling excess power reduce the level of recoverable Income from Continuing Operations -.

Utility . 170, 281 418 fuel and purchased power costs and therefore do not impact Non-utility 283 256 224 margins associated with uncapped customers. The rate orders Corporate & Other (10)

M 57) (56) also lowered PSCR revenues, which were partially offset by 443- 480 586 increased base rate and transition charge revenues.

Discontinued Operations (12) 68 46 Weather in 2004 was 3%milder than 2003, resulting in lost margins Cumulative Effect of of $25 million. Weather in 2003 was also milder than the prior year, Accounting Changes :- (27) resulting in lost margins of $114 million. The decline in margins Net Income $ 431 $ 521 $ 632 and revenues in 2004 was also due to the allocation of a smaller Diluted Earnings Per Share - portion of Detroit Edison's billings to Power Generation.

Utility $ -98i $ 1.67 $ 2.53 Non-utility 1.63 1.52 1.36 Sales Lost to Electric Choice Corporate &Other (.06) (.34) (.34) in gWh Income from Continuing Operations 2.55' 2.85 3.55

'.245i Discontinued Operations (.06) .40 .28 Cumulative Effect of Accounting Changes -_ (.16)

Net Income $ 2.49. S 3.09 $ 3.83 1 I267J I ENERGY RESOURCES 2002 2003 2004 Utility - Power Generation Operating revenues and fuel and purchased power costs decreased The power generation plants of Detroit Edison comprise our in 2004 and 2003 reflecting a $1.27 per megawatt hour (MWh) regulated power generation business. Detroit Edison's numerous (8%) decline in fuel and purchased power costs during 2004 and fossil plants, its hydroelectric pumped storage plant and its a $.64 per MWh (4%) decline during 2003. Fuel and purchased nuclear plant generate electricity. The generated electricity, power costs are a pass-through with the reinstatement of the supplemented with purchased power, is sold principally PSCR in 2004, and therefore do not affect margins or earnings throughout Michigan and the Midwest to residential, associated with uncapped customers. The decrease in fuel and commercial, industrial and wholesale customers. purchased power costs is attributable to lower priced purchases Factorsimpacting income: Power Generation earnings decreased and the use of a more favorable power supply mix driven by higher

$173 million in 2004 and $6million in 2003, compared to the prior generation output. The favorable mix is due to lower purchases, year As subsequently discussed, these results primarily reflect reduced driven by lost sales under the electric Customer Choice program.

gross margins and increased operation and maintenance expenses. The comparison was also affected by higher costs associated with 24 2004 annual report 11

substitute power purchased to meet customer demand during the and interest income includes the accrual of carrying charges on August 2003 blackout. We were required to purchase additional environmental-related regulatory assets.

power during the 36-day period it took for our generation fleet to Outlook - Future operating results are expected to vary as return to pre-blackout capacity. a result of external factors such as regulatory proceedings, fin Thousands ofMIAM) 2004 2003 2002 new legislation, changes in market prices of power, coal and Electric Sales and Use gas, plant performance, changes in economic conditions, Retail E4 37 9, 9 -43,672 48,346 weather and the levels of customer participation in the electric Wholesale and Other 8.569 5,600 6,128 Customer Choice program.

F48,948 49,272 54,474 As previously discussed, we expect cash flows and operating Internal Use and performance will continue to be at risk due to the electric Line Loss 3,574 3,248 3,651 Customer Choice program until the issues associated with this

=52.522 52,520 58,125 program are addressed. We will accrue as regulatory assets our (in Thousands ofMMW,)

unrecovered generation-related fixed costs (stranded costs)

Power Generated due to electric Customer Choice that we believe are recoverable and Purchased ' under Michigan legislation and MPSC orders. We have addressed Power Plant Generation certain issues of the electric Customer Choice program in Fossil 39,432 ;75 % 38,052 72% 39,017 67% our February 2005 rate restructuring proposal. We cannot Nuclear (Fermi 2) >'i:8,440 116 8,114 16 9,301 16 predict the outcome of these matters.

.47,872 91 46,166 88 48,318 83 In conjunction with the sale of the transmission assets of ITC in February 2003, the Federal Energy Regulatory Commission (FERC)

Purchased Power 4,550 9 6,354 12 9,807 17 froze ITC's transmission rates through December 2004. It is SystemOutput 10%

105Z52 52,520 100% 58,125 100% expected that annual rate adjustments pursuant to a formulistic pricing mechanism beginning in January 2005 will result in an Average Unit Cost ($/MWh) estimated increase in Detroit Edison's transniission expense of Generation (1) .$ 12.98 $ 12.89 $ 12.53 $50 million annually. Additionally, in a proceeding before the FERC, several Midwest utilities seek to recover transmission Purchased Power (2) i S;S 37.06; $ 41.73 $ 39.16 revenues lost as a result of a FERC order modifying the pricing Overall Average of transmission service in the Midwest. Detroit Edison estimates UnitCost r--'-'.S:15.1i $ 16.38 $ 17.02 that its potential obligation as a result of this proceeding could be I1)Represents fuel costs associated with power plants.

$2.2 million per month from December 2004 through March 2005 (2)Includes amounts associated with hedging activities. and $1million per month from April 2005 through March 2006.

Detroit Edison is expected to incur an additional $15 million in Operationand maintenance expense increased $44 million 2005 for charges related to the implementation of Midwest in 2004 and $2million in 2003. The 2004 increase reflects costs Independent Transmission System Operator's open market. As pre-associated with maintaining our generation fleet, including costs viously discussed, Detroit Edison received rate orders in 2004 that of scheduled and forced plant outages. Additionally, the increase allow for the recovery of increased transmission expenses through in 2004 is due to incremental costs associated with the implemen- the PSCR mechanism. See Note 4 - Regulatory Matters.

tation of our DTE2 project, a Company-wide initiative to improve Energy Services existing processes and to implement new core information systems, including finance, human resources, supply chain and Energy Services is comprised of Coal-Based Fuels, On-Site Energy work management. Operation and maintenance expense in both Projects and non-utility Power Generation. Coal-Based Fuels years includes higher employee pension and health care benefit operations include producing synthetic fuel from nine synfuel plants costs due to financial market performance, discount rates and and producing coke from three coke battery plants. The production health care trend rates. Expenses in 2003 were also affected by of synthetic fuel from all of our synfuel plants and the production

$5million in costs associated with the August 2003 blackout. of coke from one of our coke batteries generate tax credits under Section 29 of the Internal Revenue Code. On-Site Energy Depreciationand amortizationexpense increased $48 million Projects include pulverized coal injection, power generation, in 2004 and decreased $107 million in 2003. The variations reflect steam production, chilled water production, wastewater treatment the income effect of recording regulatory assets, which lowered and compressed air supply. Power Generation owns and operates depreciation and amortization expenses. The regulatory asset four gas-fired peaking electric generating plants and manages deferrals totaled $107 million in 2004 and $153 million in 2003, and operates two additional gas-fired power plants under representing net stranded costs and other costs we believe are contract. Additionally, Power Generation develops, operates recoverable under PA 141. and acquires coal and gas-fired generation.

Other income and deductions expense increased $17 million Factorsimpactingincome: Energy Services earnings decreased in 2004 and decreased $40 million in 2003. The 2004 increase is $11 million in 2004 and increased $17 million in 2003, compared primarily due to lower income associated with recording a return to the prior year. As subsequently discussed, these results on regulatory assets, as well as costs associated with addressing primarily reflect higher gains recognized from selling majority the structural issues of PA 141. The 2003 decrease is attributable interests in our synfuel plants, varying levels of Section 29 tax to lower interest expenses and increased interest income. credits, a gain from contract termination, uncollectible accounts Interest expense reflects lower borrowing levels and rates, written-off and losses on synfuel hedges.

2004 annual report 25

(in Millions) 2004 2003 2002 Revenues from coke sales were higher in 2004, due to higher coke Operating Revenues sales volumes combined with higher market prices, due to limited Coal-Based Fuels $ 980 $ 850 $ 559 supplies of coke in the U.S.

On-Site Energy Projects 96 70 63 Revenues from on-site energy projects increased in 2004, reflecting Power Generation - Non-utility 13 _ 9 _23 the completion of new long-term utility services contracts with 1,089 929 645 a large automotive company and a large manufacturer of paper Operation and Maintenance 1,188 1,049 708 products. Revenues in 2004 include a $9 million pre-tax fee Depreciation and Amortization 82 84 81 generated in conjunction with the development of a related Taxes other than Income 15 18 15 energy project, 50% of which was sold to an unaffiliated partner.

Gain on Sale of Interests in Synfuel Projects _ (219) (83) (40) Operationand maintenance expense increased $139 million Operating Income (Loss) 23 (119) in 2004 and $341 million in 2003, reflecting costs associated (139)

Other (Income) and Deductions (17) 2 4 with synfuel production and coke operations. Partially offsetting Minority Interest (212) the higher synfuel operating costs in 2004 was the recording of (91) (37)

Income Taxes insurance proceeds associated with an accident at one of our Provision (Benefit) 96 coke batteries. Operation and maintenance expense in 2003 (19) (30)

Section 29 Tax Credits (31) (230) (238) was affected by a $30 million pre-tax gain from the termination 64 (249) (268) of a tolling agreement at one of our generation facilities, Net Income $ 188 $ 199 $ 182 substantially offset by the establishment of a $28 million pre-tax reserve for receivables associated with a large Operatingrevenues increased $160 million in 2004 and $284 customer that filed for bankruptcy.

million in 2003 reflecting higher synfuel, coal and coke sales, Gains on sale of interests in yofelprojects increased $136 as well as increased revenues from our on-site energy projects. million in 2004 and $43 million in 2003. The improvements are The improvement in synfuel revenues results from increased due to additional sales of majority interests in our synfuel projects.

production due to additional sales of project interests in 2004 To hedge our exposure to the risk of an increase in oil prices that and 2003, reflecting our strategy to produce synfuel primarily could reduce synfuel sales proceeds, we entered into derivative and from plants in which we had sold interests in order to optinize other contracts covering approximately 65% of our 2005 synfuel cash income and cash flow, As previously discussed, operating expenses flow exposure. The derivative contracts are accounted for under the associated with syrfuel projects exceed operating revenues and mark to market method with changes in their fair value recorded as therefore generate operating losses, which have been more than an adjustment to synfuel gains. We recorded a mark to market loss offset by the resulting Section 29 tax credits. When we sell an during the 2004 fourth quarter, which reduced 2004 synfuel gains by interest in a synfuel project, we recognize the gain from such $12 million pre-tax See Note 12 for further discussion.

sale as the facility produces and sells synfuel and when there Minority interest increased $121 million in 2004 and $54 million is persuasive evidence that the sales proceeds to the Company in 2003, reflecting our partners' share of operating losses associated have become fixed or determinable and collectability is reasonably with synfuel operations. The sale of interests in our synfuel assured. In substance, we are receiving synfuel gains and reduced facilities during 2004 and 2003 resulted in allocating a larger operating losses in exchange for tax credits associated with percentage of such losses to our partners.

the projects sold.

Synrfuel earnings Income taxes increased $313 million in 2004 and $19 million (in Millions) in 2003, reflecting higher taxable earnings and a decline in the

$197 level of Section 29 tax credits due to the sale of interests in UGains on Synfuel Sales synfuel facilities.

$136 El Section 29 TaxCredits Outlook - Energy Services will continue leveraging its extensive El Operating Losses, energy-related operating experience and project management net of Minority Interest capability to develop and grow the on-site energy business. We

$0 - - _ [ expect solid earnings from our on-site energy business in 2005 as I.

a result of executing long-term utility services contracts in 2004.

2002 2003 2004 Energy Maiketing & Trading Coal marketing revenues in 2004 have also been affected by our Energy Marketing &Trading consists of the electric and gas strategy to produce synfuel primarily from plants in which we had marketing and trading operations of DTE Energy Trading and sold interests. This strategy resulted in the reduction of synfuel CoEnergy. DTE Energy Trading focuses on physical power marketing production levels. We were contractually obligated to supply coal and structured transactions, as well as the enhancement of returns to customers at certain sites that did not produce synfuel as a from DTE Energy's power plants. CoEnergy focuses on physical result of our current production strategy. To meet our obligations gas marketing and the optimization of DTE Energy's owned and to provide coal under long-term contracts with customers, we contracted natural gas pipelines and gas storage capacity. To this acquired coal that was resold to customers. The coal was sold end, both companies enter into derivative financial instruments at prices higher than the prices at which synfuel would have as part of their marketing and hedging strategies, including been sold to these customers. forwards, futures, swaps and option contracts. Most of the 26 2004 annual report

derivative financial instruments are accounted for under CoEnergys earnings in 2004 and 2003 were affected by varying the mark to market method, which results in earnings gains and losses on economic hedge contracts related to storage recognition of unrealized gains and losses from changes in assets. As subsequently discussed in the 'Outlook" section, the the fair value of the derivatives. unrealized gains and losses of economic hedge contracts are Factorsimpacting income: Energy Marketing &Trading's required to be recognized under mark-to-market accounting, earnings increased $47 million in 2004, consisting of a $4million while the offsetting unrealized losses and gains on the underlying improvement at DTE Energy Trading and a $43 million improve- asset positions are not recognized.

ment at CoEnergy. Earnings increased $20 million in 2003, CoEnergy's earnings in 2004 reflect a $74 million one-time of which $18 million was attributable to DTE Energy Trading pre-tax gain from modifying a future purchase commitment under and $2million to CoEnergy. a transportation agreement and terminating a related long-term DTE Energy Trading's earnings improvement in 2004 and 2003 gas exchange (storage) agreement with an interstate pipeline was primarily due to realized margins associated with short-term company. Under the gas exchange agreement, we received gas physical trading and origination activities. from the customer during the summer injection period and redelivered the gas during the winter heating season.

(inMillions) 2004 2003 2002 OTE Energy Trading The realized and unrealized margins comparison for both Margins - Gains (Losses) ', .

DTE Energy Trading and CoEnergy was affected by our decision Realized (1) . X83 $ 82$ 38 in late 2003 to monetize certain in-the-money derivative contracts Unrealized (2): while simultaneously entering into replacement at-the-market Proprietary Trading (3) (7) (7) - contracts. The monetizations were completed in corjunction Structured Contracts (4) 3 (2) 13 with implementing a series of initiatives to improve cash flow and Economic Hedges (5) 11' - - fully utilize Section 29 tax credits. Although the monetizations Total Unrealized Margins (3) (9) 13 did not impact earnings, they had the effect of decreasing realized Total Margins 80 73 51 margins and increasing unrealized margins on economic hedges Operating and Other Costs -'29 28 29 in 2004, and having the opposite effect on margins in 2003.

Income Tax Provision 15 13 8 Outlook - Energy Marketing &Trading will seek to manage its Net Income $ r36$ 32 $ 14 business in a manner consistent with, and complementary to, CoEnergy the growth of our other business segments.' Gas storage and Margins - Gains (Losses) (7) transportation capacity enhances our ability to provide reliable Realized (1) S -(42) $ 168 $ 32 and custom-tailored bundled services to large-volume end users Unrealized (2): and utilities. This capacity, -coupled with the synergies from i

ProprietaryTrading (3) -~ 4 9 DTE Energy's other businesses, positions the segment to add value.

Structured Contracts (4) (1) (1) 22 Significant portions of the Energy Marketing &Trading portfolio Economic Hedges (5) 68' (138) 193) are economically hedged. The portfolio includes financial instru-Gas in Inventory (6) - - 74 Total Unrealized Margins 67 (135) 12 ments and gas inventory, as well as owned and contracted natural Total Margins 25 33 44 gas pipelines and storage assets. The financial instruments are Gain from Contract deemed derivatives, whereas the gas inventory, pipelines and stor-Modification/Termination (744) age assets are not considered derivatives for accounting purposes.

Operating and Other Costs , :12 ; 13 27 As a result, Energy Marketing &Trading will experience earnings Income Tax Provision - i 31 7 6 volatility as derivatives are marked to market without revaluing Net Income 1S ~56 $ 13 $ 11 the underlying non-derivative contra6ts and assets. The majority of Total Energy Marketing such earnings volatility is associated with the natural gas storage

&Trading Net Income iS- 92$ $ 45 $ 25 cycle, which runs annually from April of one year to March of the (1)Realized margins include the settlement of all derivative and non-derivative next year. Our strategy is to economically hedge the'price risk of contracts, as well as the amortization of deferred assets and liabilities. all gas purchases for storage with sales in the over-the-counter (21Unrealized margins include mark-to-market gains and losses on derivative ' (forwards) and futures markets. Current accounting rules require contracts, net of gains and losses reclassified to realized. See 'Fair Value of the marking to market of forward sales and futures, but do not Contracts' section that follows.

(3) Proprietary Trading' represents the net unrealized effect of actively traded allw'for'the marking to market of th'e irlated gas inventory. This positions entered into to take advantage of market price movements. - - results in gains and losses that are recognized in different interim (4) Structured Contracts represent the net unrealized effect of derivative and annual accounting periods. We anticipate the financial impact transactions entered into with the intent to capture profits by originating of this timing difference will reverse by the end of each storage substantially hedged positions with wholesale energy marketers, utilites, retail aggregators and alternative energy suppliers. cycle. See "Fair Value of Contracts' section that follows.

(5) EconomicHedges representthe net unrealized effect of derivative actvity associated with assets owned or contracted for by DTE Energy, including Non-utility - Other forward sales of gas production and trades associated with transportation Our other non-utility businesses include our Coal Services and and storage capacity.

16)Gas ininventory margins represent gains associated with fair value Biomass units. Coal Services provides fuel, transportation and accounting in2002. CoEnergy changed its method of accounting for inventory rail equipment management services. We specialize in minimizing inJanuary 2003 (Note 2). fuel costs and maximizing reliability of supply for energy-intensive (7)Excludes the impact on margins from the modification of a transportation agreement with an interstate pipeline company. customers. Additionally, we participate in coal trading and 2004 annual report 27

coal-to-power tolling transactions, as well as the purchase and (inThousands of MM) 2004 2003 2002 sale of emissions credits. Coal Services has formed a subsidiary, Electric Deliveries DTE PepTec Inc., which uses proprietary technology to produce Residential 15,08VI 15,074 15,958 high quality coal products from fine coal slurries typically discarded Commercial 13,4251i 15,942 18,395 from coal mining operations. Biomass develops, owns and Industrial ; 1,472 12,254 13,590 operates landfill recovery systems in the U.S. Gas produced from Wholesale 2.197T. 2,241 2,249 many of these landfill sites qualifies for Section 29 tax credits. Other 401 402 403 Factorsimpacting income: Earnings increased $3 million in 2.576 45,913 50,595 2004 and declined $9million in 2003. The 2004 increase reflects Electric Choice 9,245 6,193 2,967 higher sales from coal and emissions credits, partially offset Electric Choice -Self Generations* 595 1,088 543 by increased costs associated with our waste coal operations. Total Electric Deliveries 52416 53,194 54,105 The 2003 decline reflects reduced marketing and tolling income

Represents deliveries for self generators who have purchased power from as well as an increase in operating costs associated with ramping alternative energy suppliers to supplement their power requirements.

up the DTE PepTec business. Our first waste coal facility in Ohio Operatingrevenues increased $111 million in 2004, primarily became operational in late 2003. due to an increase in base rates resulting from the interim and (Dollars in Millions) 2004 2003 2002 final rate orders. The 2004 improvement is also attributable to residential sales growth and the allocation of a higher portion of Coal Services Detroit Edison's billings to Power Distribution, partially offset by Tons of coal shipped (inmillions) 39.9 32.0 28.5 the effects of milder weather. Operating revenues decreased Biomass

$96 million in 2003, reflecting mild summer weather and the Gas Produced (inBcf) 23.2' 26.8 27.5 impact of slower economic conditions.

Tax Credits Generated (1) $ 7.74 $ 10.5 $ 12.9 (1DTE Energy's portion of total tax credits generated. Operationand maintenance expense decreased $1million in 2004 and increased $75 million in 2003. The operation and Outlook - We expect to continue to grow our Coal Services and maintenance expense comparability was affected by 2003 Biomass units. We believe a substantial market could exist for restoration costs associated with three catastrophic storms and the use of DTE PepTec Inc. technology and we continue to modify and the August 2003 blackout. Both years were also affected by prove out this technology. Coal Services and Biomass have formed a an increase in reserves for uncollectible accounts receivable, new subsidiary to enter the coal mine methane business. Ae purchased reflecting high past due amounts attributable to economic coal mine methane assets in Illinois at the end of 2004, and expect to conditions, and an increase in employee benefit costs. Additionally, reconfigure equipment and restart operations by mid-2005. the comparisons were affected by incremental costs associated The Section 29 tax credits generated by Biomass are subject to the with our DTE2 project implementation, a $22 million pre-tax loss same phase out risk if domestic crude oil prices reach certain levels, in 2003 from the sale of our steam heating business, and the accrual as detailed in the synthetic fuel operations discussion. See Note 13. of refunds in 2004 and 2003 associated with transmission services.

ENERGY DISTRIBUTION Storm Restoration Costs (in Millions)

Utility - Power Distribution Power Distribution operations include the electric distribution : $72 services of Detroit Edison. Power Distribution distributes electric-ity generated and purchased by Energy Resources and alternative $48'I-I-J" 7_-0 energy suppliers to Detroit Edison's 2.1 million customers.

!i,

-V.rm Factorsimpacting income: Power Distribution earnings increased .

I

$71 million during 2004 and decreased $94 million in 2003, compared a MMEE to the prior year. As subsequently discussed, these results primarily 2002 2003 2004 reflect varying operating revenues and operation and maintenance Outlook - Operating results are expected to vary as a result of expenses, as well as a non-recurring loss recorded in 2003. external factors such as weather, changes in economic conditions and the severity and frequency of storms.

(inMillions) 2004 2003 2002 Operating Revenues $ 1,358 $ 1,247 $ 1,343 We experienced numerous catastrophic storms over the past few Fuel and Purchased Power 17' 19 26 years. The effect of the storms on annual earnings was partially Operation and Maintenance - 723t 724 649 offset by storm insurance. We have been unable to obtain storm Depreciation and Amortization ; 251 249 246 insurance at economical rates and as a result, we do not anticipate Taxes OtherThan Income 101 100 117 having insurance coverage at levels that would significantly offset Operating Income 266 155 305 unplanned expenses from ice storms, tornadoes, or high winds Other (Income) and Deductions 137. 128 136 that damage our distribution infrastructure.

Income Tax Provision 41 10 58 Non-Utility NetIncome S 88 $ 17 $ 111 Operating Income as a Non-utility Energy Distribution operations consist of DTE Energy Percent of Operating Revenues 20% 12% 23% Technologies, which assembles, markets, distributes and services distributed generation products, provides application engineering, and monitors and manages on-site generation system operations.

28 2004 annual report 11

Factorsimpacting income: Non-utility results declined tin BcIt 2004 2003 2002

$4million in 2004 and improved $1million in 2003. The 2004 Gas Markets decrease includes an impairment charge for an "other than Gas sales :173 181 174 temporary" decline in the fair value of an investment in a joint End usertransportation .145 152 171 venture that supplied certain distributed generation equipment 318 333 345 and materials to DTE Energy Technologies. Intermediate transportation 536 576 492 Outlook - DTE Energy Technologies will focus on sales of - 8:54 909 837 proprietary pre-engineered and packaged continuous generation products in key applications. This will likely result in near-term Operationand maintenanceexpense increased $29 million revenue decline, but we anticipate gross profit margins will in 2004 and $74 million in 2003, reflecting higher reserves for improve. Combined with continuing cost reductions and uncollectible accounts receivable and pension and health care resumption of sales growth, we believe these actions will lead costs. The increase in uncollectible accounts expense reflects to improved financial performance in 2005. high past due amounts attributable to an increase in gas prices, continued weak economic conditions and a lack of adequate ENERGY GAS public assistance for low-income customers.

Utility - Gas Distribution Gas Distribution operations include gas distribution services Uncollectible Accounts Expense primarily provided by MichCon, our gas utility that purchases, (inMillions) stores, distributes and sells natural gas to 1.2 million residential, commercial and industrial customers located throughout Michigan. $60 Factorsimpacting income: Gas Distribution's earnings declined

$9million in 2004 and $37 million in 2003, compared to the prior year. As subsequently discussed, results primarily reflect varying I`+'$21`. A gross margins, higher operation and maintenance expenses and IF-a non-recurring loss recorded in 2003.

2002 2003 2004 (inMillions) 2004 2003 2002 Operating Revenues M Ile82 $ 1,498 $ 1,369 Other income and deductions expense increased $12 million in Cost of Gas i. 711 909 774 2004 and decreased $5million in 2003, reflecting a 2003 gain on Gross Margins t 11 589 595 sale of interests in a series of real estate partnerships.

Operation and Maintenance 400 371 297 Income taxes in 2004 and 2003 were impacted by lower earnings Depreciation and Amortization -1 03 101 104 and favorably affected by an increase in the amortization of tax Taxes Other Than Income 49 52 51 benefits previously deferred in accordance with MPSC regulations.

Operating Income 59 65 143 Outlook - Operating results are expected to vary as a result of Other (income) and Deductions ..48 36 41 external factors such as regulatory proceedings, weather and Income Tax Provision (Benefit) {9) - 36 changes in economic conditions. Higher gas prices and economic Net Income $ 20 $ 29 $ 66 conditions have resulted in an increase in past due receivables.

Operating Income as a We believe our allowance for doubtful accounts is based on Percent of Operating Revenues 4 reasonable estimates. However, failure to make continued Gross margins increased $22 million in X2004 and decreased progress in collecting past due receivables would unfavorably

$6million in 2003, compared to the prioi year. The improvement in affect operating results. Energy assistance programs funded by 2004 reflects the impact of interim rate irelief and additional margin the federal government and the State of Michigan remain critical from the acceleration of several midstre, am services Contracts. to MichCon's ability to control uncollectible accounts receivable Partially offsetting these improvements vvere lower sales and end expenses. We are working with the State of Michigan and others user transportation deliveries due to miliJer weather. The gross to increase the share of funding allocated to our customers to margin comparison was also affected by; a $26.5 million pre-tax be representative of the number of low-income individuals in reserve recorded in 2003 for the potentiaaIdisallowance in gas costs our service territory.

pursuant to an MPSC order in MichCon's;2002 gas cost recovery: As a result of the continued increase in operating costs, (GCR) plan case (Note 4). Operating rev enues and cost of gas MichCon filed a rate case in September 2003 to increase rates increased significantly in 2004 and 2003: reflecting higher gas prices, by $194 million annually to address future operating costs and which are recoverable from customers tt urough the GCR mechanism. other issues. MichCon received an interim order in this rate (inMillions} 2004 2003 2002 case in September 2004 increasing rates by $35 million annually.

Gas Markets . - The MPSC Staff has recommended a provision that would allow Gas sales t$ A1.435 $ 1,242 $ 1,135 MichCon to recover or refund 90% of uncollectible accounts End usertransportation 1 119 136 122 receivable expense above or below the amount that is reflected 1,554 1,378 1,257 in base rates. See Note 4 - Regulatory Matters.

Intermediate transportation , -56 51 48 Other 72 69 64 S 1,682 $ 1,498 $ 1,369 2004 annual report 29

Non-utility the marketing of SMGC for sale. Under U.S. generally accepted Non-utility operations include the Gas Production business and the accounting principles, we classified SMGC as a discontinued Gas Storage, Pipelines & Processing business. Our Gas Production operation in 2004 and recognized a net of tax impairment loss business produces gas from proven reserves in northern Michigan of approximately $7million, representing the write-down to fair and sells the gas to the Energy Marketing &Trading segment. value of the assets of SMGC, less costs to sell, and the write-off of Gas Storage, Pipelines & Processing has a partnership interest allocated goodwill. In November 2004, we entered into a definitive in an interstate transmission pipeline, seven carbon dioxide agreement providing for the sale of SMGC. Following receipt of processing facilities and a natural gas storage field, as well as regulatory approvals and resolution of other contingencies, it is lease rights to another natural gas storage field. The assets of these anticipated that the transaction will close in 2005.

businesses are well integrated with other DTE Energy entities. InternationalTransmission Company - In February 2003, Factorsimpacting income: Earnings decreased $8million in we sold ITC, our electric transmission business, to affiliates of 2004 and increased $3million in 2003. The decline in 2004 is due Kohlberg Kravis Roberts &Co. and Trimaran Capital Partners, to gains recorded in 2003 from selling our 16% pipeline interest in LLC. Accordingly, we classified ITC as a discontinued operation.

the Portland Natural Gas Transmission System, as well as from The sale generated a preliminary net of tax gain of $63 million selling certain gas properties. Excluding those gains, income in 2003. The gain was net of transaction costs, the portion of the increased $2million reflecting the acquisition of an additional gain that was refundable to customers and the write off of approxi-15% ownership in the Vector Pipeline in late 2003, increased sales mately $44 million of allocated goodwill. The gain was lowered of transportation capacity by Vector Pipeline and increased storage to $58 million in 2004 under the MPSC's November 2004 final sales throughout 2004.

rate order that resulted in a revision of the applicable transaction Outlook - We anticipate further expansion of our storage costs and customer refund. W'e had income from discontinued facilities and Vector pipeline to take advantage of available operations of $5million in 2003.

growth opportunities. We are also seeking to secure markets for our 10.5% interest in the Millennium Pipeline. See Note 3 for further discussion.

We expect to continue developing our gas production properties CUMULATIVE EFFECT in northern Michigan and leverage our experience in this area OF ACCOUNTING CHANGES by pursuing investment opportunities in unconventional gas As required by U.S. generally accepted accounting principles, production outside of Michigan. During 2004, we acquired on January 1,2003, we adopted new accounting rules for asset approximately 50,000 leasehold acres in the southern region retirement obligations and energy trading activities. The cumula-of the Barnett shale in Texas, an area of increasing production. tive effect of adopting these new accounting rules reduced 2003 We began drilling test wells in December 2004 and anticipate earnings by $27 million. See Note 2 for further discussion.

drilling a significant number of additional test wells in the first half of 2005. Initial results from the test wells are expected in CAPITAL RESOURCES AND LIQUIDITY mid-2005. If the results are successful, we could commit up DTE Energy and its subsidiaries require cash to operate and cash to $350 million of capital over the next several years to develop is provided by both internally and externally generated sources.

these properties. We manage our liquidity and capital resources to maintain financial CORPORATE & OTHER flexibility to meet our current and future cash flow needs, Corporate & Other includes various corporate support functions Cash Requirements such as accounting, legal and information technology. As these Wle use cash to maintain and expand our electric and gas utilities functions essentially support the entire Company, their costs are and to grow our non-utility businesses, in addition to retiring fully allocated to the various segments based on services utilized and paying interest on long-term debt and paying dividends.

and therefore the effect of the allocation on each segment can Our strategic direction anticipates base level capital investments vary from year to year. Additionally, Corporate &Other holds and expenditures for existing businesses in 2005 of up to certain non-utility debt and investments, including assets held $1.1 billion. The capital needs of our utilities will increase for sale and in emerging energy technologies. due primarily to environmental related expenditures.

Factorsimpacting income: Corporate &Other results improved

$47 million in 2004, compared to a $1million decline in 2003. Capital spending for general corporate purposes will increase The 2004 improvement was affected by a $14 million net of tax in 2005, primarily as a result of DTE2 and environmental gain from the sale of 3.5 million shares of Plug Power stock spending. We began implementing the DTE2 project in 2003.

(Note 1), as well as lower Michigan Single Business Taxes, resulting The Company expects the project to incrementally cost from tax saving initiatives. Results for 2003 include a $15 million approximately $160 million to $175 million.

cash contribution to the DTE Energy Foundation, funded with The EPA ozone transport regulations and final new air quality proceeds received from the sale of ITC. Corporate & Other also standards relating to ozone and particulate air pollution will benefited from lower financing costs and increased intercompany continue to impact us. Detroit Edison estimates that it will spend interest income in both periods. approximately $100 million in 2005 and incur up to an additional DISCONTINUED OPERATIONS $1.3 billion of future capital expenditures over the next five to eight years to satisfy both existing and proposed new control Southern Missouri Gas Company (SMGC) - We own SMGC, a requirements. The full recovery of $550 million of environmental public utility engaged in the distribution, transmission and sale of expenditures was authorized in the MPSC's November 2004 natural gas in southern Missouri. In 2004, management approved final rate order.

30 2004 annual report 1I

Non-utility capital spending will approximate $100 million to reflects an increase of over $300 million in net income, after

$300 million annually for the next several years. Capital spending adjusting for non-cash items (depreciation, depletion, amortization, for growth of existing or new businesses will depend on the deferred taxes and gains), substantially offset by a $259 million existence of opportunities that meet our strict risk-return increase in working capital and other requirements. A portion and value creation criteria. of this improvement is attributable to the change in our strategy Debt maturing in 2005, excluding securitization debt, totals to primarily produce synfuel from plants in which we have sold approximately $410 million. interests. As previously discussed, synfuel projects generate operating losses, which have been more than offset by tax credits We believe that we will have sufficient internal and external that we have been unable to fully utilize, thereby negatively capital resources to fund anticipated capital requirements.

affecting operating cash flow. Cash for working capital primarily (inMillions) 2004 2003 2002; reflects higher income tax payments of $172 million in 2004, Cash and Cash Equivalents - reflecting a different payment pattern of taxes in 2004 compared Cash Flow From (Used For) - to 2003. The increase in working capital was mitigated by Company Operating activities: initiatives to improve cash flow, including better inventory Net income $ -431 $ 521 $ 632 management, cash sales transactions, deferral of retirement Depreciation, depletion plan contributions and the utilization of letters of credit.

and amortization 744 691 759 Certain cash initiatives in 2003 lowered cash flow in 2004.

Deferred income taxes 129 (220) (208)

Our net operating cash flow in 2003 was $950 million, reflecting Gain on sale of ITC, synfuel -

and other assets, net (236) (228) (40) a $46 million decline from 2002. The decrease was attributable Working capital and other ' -(73) 186 (147) to lower utility net income, after adjusting foir non-cash items.

995 950 996 Partially offsetting the declines were lower working capital and Investing activities: other requirements reflecting Company initiatives to improve Plant and equipment cash flow and optimize synfuel operations. The improvement expenditures - utility (815) (679) (794) in 2003 working capital was achieved despite a $222 million Plant and equipment 1'ir- contribution to our pension plans.

expenditures -non-utility (89) (72) (190) Outlook - We expect cash flow from operations to increase Investment injoint ventures (36) (34) (21) over the long-term primarily due to improvements from utility Proceeds from sale of ITC, V.l ' rate increases and the sales of interests in our synfuel projects.

synfuels and other assets If i k325 758 41 This'will be partially offset by higher cash requirements,' primarily Restricted cash and ,-. within our gas storage business. We are continuing our efforts other investments (66) 37 (151) to identify opportunities to improve cash flow through cash

- (681) 10 (1,115) improvement initiatives.

Financing activities: I t Operating cash flow from our utilities is expected to increase in Issuance of long-term debt 2005, but will be affected by the level of sales migration under and common stock 777, 571 1,403 the electric Customer Choice program and the ability of the MPSC Redemption of long-term debt (759) (1,208) (793) within the regulatory processes to put in place a Custo6mer Choice Short-term borrowings, net , 33 (44) (267) program that has sound economic fundamentals. In addition, the rora. ,the., .,.. me .

Dividends on common . Customer Choice program's impact will also be determined by the stock and other (363) (358) (359) success of the Company in addressing certain structural flaws within (312) (1,039) (16) additional regulatory proceedings and the legislative process.

Net Increase (Decrease) in Cash and Cash Equivalents 1$ `'2 $ (79) $ (135) Another factor affecting utility cash flows is the degree and timing of rate relief within the electric and gas rate cases.

Cash from Operating Activities Based on the final and interim orders issued by the MPSC in 2004, A majority of the Company's operating cash flow is provided by our approximately $50 miiion of additional revenues were'realized in two utilities, which are significantly influenced by factors such as the 2004 calendar year. Due to the structure 'of the inteim and weather, electric Customer Choice sales loss, regulatory deferrals, final rate orders, we will not realizie'the full benefitsof interlim and regulatory outcomes, economic conditions and operating costs.' finalrate relief until 2006 when all customer rate caps expire.

Our non-utility businesses also provide sources of cash flow to the Improvements in cash flow from our utilities are also expected enterprise and reflect a range of operating profiles. The profiles from better management of our working capital requirements, vary from our synthetic fuels business, which we believe will including the c6ntinued focus on' reducing past due accounts provide over $1.6 billion in cash through 2008,' to new start-ups:I receivable. Our emphasis in these businesses'will continue to These new start-ups include our unconventional gas'and waste be centered around cash generation and conservati'on.

coal recovery businesses, which we are growing and, if successful, Cash flows from our synfuel business are expected to total approxi-could require significant investments. mately $1.6 billion between 2005 and 2008. The redeployment of Although DTE Energ"ys overall earnings'were $431 million in 2004, this cash represents a unique opportunity to increase shareholder cash from operations totaling $995 million was up $45 milion from value and strengthen our balance sheet. We expect to use this cash the comparable 2003 period. The operating cash flow comparison 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 mostly in the form of commercial paper borrowings, provide us repurchase common stock if adequate investment opportunities with the liquidity needed on a daily basis. Our commercial paper are not available. Our objectives for cash redeployment are to program is supported by our unsecured credit facilities.

strengthen the balance sheet and coverage ratios in order to DTE Energy and its subsidiaries have a total of $1.675 billion in improve our current credit ratings and outlook, and to more credit facilities, which provide liquidity to our commercial paper than replace the value of synfuels. programs and support the use of letters of credit.

Cash flows from our synfuel business are expected to approximate (inMillions) FacilityAmount Maturity Date

$400 million in 2005. The source of synfuel cash flow includes cash Issuing Entity from operations (excluding certain working capital changes), asset DTE Energy $ 375.00 5/5/2006 sales, and the utilization of Section 29 tax credits carried fonvard DTE Energy 175.00 10/24/2006 from synfriel production prior to 2004. DTE Energy 525.00 10/15/2009 Our other operating non-utility businesses are expected Detroit Edison 68.75 10/24/2006 to contribute approximately $400 million through 2008. Detroit Edison 206.25 10/15/2009 Remaining start-up businesses such as unconventional gas MichCon 81.25 10/24/2006 production, waste coal recovery and distributed generation will MichCon 243.75 10/15/2009 continue to use cash in excess of their cash generation over the $ 1,675.00 next couple of years while they are being further developed.

Certain of the previously discussed cash initiatives resulted in Borrowings under the facilities are available at prevailing accelerating the receipt of cash in 2004, which will have the short-term interest rates. The agreements require each of the impact of lowering cash flow in 2005. Companies to maintain a debt to total capitalization ratio of no more than .65 to 1and an "earnings before interest, taxes, Cash from Investing Activities depreciation and amortization" (EBITDA) to interest ratio of no Cash inflows associated with investing activities are primarily less than 2 to 1.DTE Energy has significant room under these generated from the sale of assets. In any given year, we will look provisions, with coverage totaling 4.3 to 1 and leverage at .489 to harvest cash from under performing or non-strategic assets. to I at December 31, 2004. The Companies are currently in Capital spending within the utility business is primarily to main- compliance with these financial covenants. Should either tain our generation and distribution infrastructure, comply with Detroit Edison or AlichCon have delinquent debt obligations of environmental regulations and gas pipeline replacements. Capital at least $25 million to any creditor, such delinquency will be spending within our non-utility businesses is for ongoing mainte- considered a default under DTE Energy's credit agreements.

nance and some expansion. The balance of non-utility spending These agreements have standard material adverse change (MAC) is for growth, which we manage very carefully. We look to make clauses, however, the agreements expiring in October 2009 include investments that meet strict criteria in terms of strategy, manage- a provision that the MAC clause does not apply when borrowings ment skills, risks and returns. All new investments are analyzed are made to repay maturing commercial paper.

for their rates of return and cash payback on a risk adjusted basis. Additionally, Detroit Edison has a $200 million short-term WMe have been disciplined in how we deploy capital and will not financing agreement secured by customer accounts receivable.

make investments unless they meet our criteria. For new business The agreement contains certain covenants related to the lines, we invest tentatively based on research and analysis. Based delinquency of accounts receivable. Detroit Edison is currently on a limited investment, we evaluate results and either expand or in compliance with these covenants.

exit the business based on those results. In any given year, the amount of growth capital will be determined by the underlying For additional information see Note 10 - Short-Term Credit cash flows of the Company with a clear understanding of any Arrangements and Borrowings.

potential impact on our credit ratings. Our strategy is to have a targeted debt portfolio blend as to Net cash relating to investing activities declined $691 million in fixed and variable interest rates and maturity. We continually 2004 and improved $1.1 billion in 2003, compared to the prior year. evaluate our leverage target, which is currently 50% or lower, The changes were primarily due to proceeds received in 2003 total- to ensure it is consistent with our objective to have a strong ing $758 million from the sale of ITC, interests in three synfuel investment grade debt rating. We have completed a number of projects and non-strategic assets. Additionally, the changes are refinancings with the effect of extending the average maturity due to variations in cash contractually designated for debt service. of our long-term debt and strengthening our balance sheet.

The extension of the average maturity was accomplished at Longer term, with the expected improvement at our utilities and interest rates that lowered our debt costs.

continued cash generation from the synfuel business, cash flows Net cash used for financing activities improved $727 million in are expected to improve. We will continue to pursue opportunities 2004 and declined $1.0 billion in 2003, compared to the prior periods.

to grow our businesses in a disciplined fashion if we can find opportunities that meet our strategic, financial and risk criteria. The 2004 change was primarily due to higher issuances of new long and short-term debt and fewer repurchases of long-term debt.

Cash from Financing Activities The 2003 change was due to higher redemptions of long-term debt We rely on both short-term borrowings and longer-term financings and lower proceeds from issuances of new debt and common stock as a source of funding for our capital requirements not satisfied by For additional information on debt issuances and redemptions, the Company's operations. Short-term borrowings, which are 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 We have issued guarantees for the benefit of various non-utility not have current shelf capacity. In 2005, we plan on filing new subsidiaries. In the event that our credit rating is downgraded to shelf registration statements for MichCon and Detroit Edison. below investment grade, certain of these guarantees would require Common stock issuances or repurchases can also be a source us to post cash'or letters of credit valued at approximately $356 or use of cash. In January 2005, we announced the DTE Energy million at December 31, 2004. Additionally, our trading business Board has authorized the repurchase of up to $700 million in' could be required to restrict operations and our access to the short-common stock through 2008. The authorization provides Compay term commercial paper market could be restricted or eliminated.

management with flexibility to pursue share repurchases from While we currently do not anticipate such a downgrade, we cannot time to time, and will depend on future cash flows and investment predict the outcome of current or future reviews. The following opportunities. In January 2005, we discontinued issuing new table shows our credit rating as determined by three nationally DTE Energy shares for our dividend reinvestment plan, which respected credit rating agencies. AU ratings are considered generated approximately $50 million annually. We also investment grade and affect the value of the related securities.

contributed $170 million of DTE Energy common stock to Credit Rating Agency our pension plan in the first quarter of 2004. Moody's Standard Investors Fitch Contractual Obligations Entity Description &Poors Service Ratings DTE Energy Senior Unsecured Debt BBB- Baa2

BBB The following table details our contractual obligations for debt Commercial Paper A-2 P-2* F2 redemptions, leases, purchase obligations and other long-term Detroit Edison Senior Secured Debt BBB+ A3* A-obligations as of December 31, 2004: Commercial Paper A-2 p-2* F2 Less Than 1-3 4-5 After MichCon Senior Secured Debt BBB A3 A-On Millions) Tot al 1Year Years Years 5Years Commercial Paper A-2 P-2 F2 Contractual Obligations

Currently on negative outlook Long-Term Debt Mortgage bonds, CRITICAL ACCOUNTING ESTIMATES notes & other $ 6,0'91 S 410 $ 1,224 S 759 $ 3,698 There are estimates used in preparing the consolidated financial Securitization bonds 1A,36 96 335 272 793 statements that require considerable judgment. Such estimates Equity-linked securities 178 5 173 relate to regulation, risk management and trading activities, Trust preferred-linked securities 21 39 289 Section 29 tax credits, goodwill, pension and postretirement costs, Capital lease obligations 34 11 34 20 29 the allowance for doubtful accounts, and legal and tax reserves.

Interest 6,3 494 1,280 726 3,846 Regulation Operating leases 6;23 64 143 75 341 Electric, gas, fuel, Asignificant portion of our business is subject to regulation.

transportation & storage Detroit Edison and MichCon currently meet the criteria of purchase obligations* 6,1: 30 3,694 1,601 236 599 Statement of Financial Accounting Standards (SFAS) No. 71, Other long-term "Accountingfor the Effects of Certainljrpes of 1egulationg" obligations 3'57 97 151 37 72 Application of this standard results in differences in the application Total Obligations $ 21,604 $ 4,871 $ 4,941 $ 2,125 $ 9,667 of generally accepted accounting principles between regulated and

Excludes amounts associated with full requirements contracts where no non-regulated businesses. SFAS No. 71 requires the recording stated minimum purchase volume is required.

of regulatory assets and liabilities for certain transactions that Credit Ratings wotild have been treated as revenue or expense in non-regulated Credit ratings are intended to provide banks and capital market businesses. Future regulatory changes or changes in the competitive participants with a framework for comparing the credit quality environment could result in discontinuing the application of SFAS of securities and not a recommendation to buy, sell or hold No. 71 for some or all of our businesses. If we were to discontinue securities. Management believes that the current credit ratings the application of SFAS No. 71 on all our operations, we estimate of the Company provide sufficient access to the capital markets. that the extraordinary loss would be as follows:

However, disruptions in the banking and capital markets not ran Millions) specifically related to DTE Energy may affect the Company's utility ability to access these funding sources or cause an increase in Detroit Edison* $ (138) the return required by investors. MichCon (42)

In November 2004, Moody's Investors Service and Fitch Ratings Total $ (180) downgraded MichCon. In December 2004, Standard &Poor's

Excludes securitized regulatory assets downgraded DTE Energy, Detroit Edison and MichCon. The Management believes that currently available facts support the ratings reflect weaker credit metrics due to decreased cash flows mainly stemming from increased operation and maintenance continued application of SPAS No. 71 and that all regulatory assets costs without sufficient regulatory relief. Additional unfavorable and liabilities are recoverable or refundable in the current rate changes in our ratings could restrict our ability to access capital environment (Note 4).

markets at attractive rates and increase our borrowing costs.

2004 annual report 33

Risk Management and Trading Activities reporting units with goodwill is required to perform impairment All derivatives are recorded at fair value and shown as "Assets or tests annually or whenever events or circumstances indicate that liabilities from risk management and trading activities" in the the value of goodwill may be impaired. In order to perform these consolidated statement of financial position. Risk management impairment tests, we must determine the reporting unit's fair value activities are accounted for in accordance with SFAS No. 133, using valuation techniques, which use estimates of discounted "Accountingfor Derivative Instruments and HedgingActivities," future cash flows to be generated by the reporting unit. These cash as amended. Through December 2002, trading activities were flow valuations involve a number of estimates that require broad accounted for in accordance with Financial Accounting Standards assumptions and significant judgment by management regarding Board (FASB) Emerging Issues Task Force (EITF) Issue No. 9810, future performance. To the extent estimated cash flows are revised "AccountingforEnergy Rlading and Risk Management downward, the reporting unit may be required to write down all or a Activities." Effective January 2003, trading activities are portion of its goodwill, which would adversely impact our earnings.

accounted for in accordance with SFAS No. 133. As of December 31, 2004, our goodwill totaled $2.1 billion. The See Note 2 - New Accounting Pronouncements. majority of our goodwill is allocated to our utility reporting units, The offsetting entry to "Assets or liabilities from risk management with approximately $772 million allocated to the utility Energy Gas and trading activities" is to other comprehensive income or earn- reporting unit. The value of the utility reporting units is signifi-ings depending on the use of the derivative, how it is designated cantly impacted by rate orders and the regulatory environment.

and if it qualifies for hedge accounting. The fair values of derivative The utility Energy Gas reporting unit is comprised primarily of contracts were adjusted each reporting period for changes using MichCon. We have made certain cash flow assumptions for market sources such as: MichCon that are dependent upon the successful outcome of the

published exchange traded market data outstanding gas rate case (Note 4). These assumptions may change

prices from external sources when we receive a final rate order, which is expected during the first quarter of 2005.

price based on valuation models Based on our 2004 goodwill impairment test, we determined Market quotes are more readily available for short duration that the fair value of our reporting units exceed their carrying contracts. Derivative contracts are only marked to market to the value and no impairment existed. We will continue to monitor extent that markets are considered highly liquid where objective, regulatory events, and evaluate their impact on our valuation transparent prices can be obtained. Unrealized gains and losses assumptions and the carrying value of the related goodwill.

are fully reserved for transactions that do not meet this criterion. While we believe our assumptions are reasonable, actual results Section 29 Tax Credits may differ from our projections.

We generate Section 29 tax credits from our synfuel, coke battery Pension and Postretirement Costs and biomass operations. We recognize earnings as tax credits are generated at our facilities in one of two ways. First, to the extent Our costs of providing pension and postretirement benefits are we generate credits to our own account, we recognize earnings dependent upon a number of factors, including rates of return on through reduced tax expense. Second, to the extent we have plan assets, the discount rate, the rate of increase in health care sold an interest in our synfuel facilities to third parties, we costs and the amount and timing of plan sponsor contributions.

recognize gains as synfuel is produced and sold, and when there We had pension costs for qualified pension plans of $81 million in is persuasive evidence that the sales proceeds have become fixed 2004, $47 million in 2003, and pension income of $9million in or determinable and collectibility is reasonably assured. 2002. Postretirement benefits cost for all plans were $125 million All Section 29 tax credits taken after 1997 are subject to audit by in 2004, $118 million in 2003, and $70 million in 2002. Pension and the IRS, however, all of our synthetic fuel facilities have received postretirement benefits cost for 2004 is calculated based upon a favorable private letter rulings from the IRS with respect to their number of actuarial assumptions, including an expected long-term operations. Audits of four of our synfuel facilities for the years 2001 rate of return on our plan assets of 9.0%. In developing our expect-and 2002 were successfully completed during 2004. One synfuel ed long-term rate of return assumption, we evaluated input from our facility is currently under audit If our Section 29 tax credits were consultants, including their review of asset class risk and return disallowed in whole or in part as a result of an IRS audit, there expectations as well as inflation assumptions. Projected returns could be a significant write-off of previously recorded earnings are based on broad equity and bond markets. Our expected long-from such tax credits. term rate of return on plan assets is based on an asset allocation Tax credits generated by our facilities were $449 million in 2004, assumption utilizing active investment management of 65% in as compared to $387 million in 2003 and $351 million in 2002. equity markets, 28% in fixed income markets, and 7%invested The portion of tax credits generated for our own account were $38 in other assets. Because of market volatility, we periodically million in 2004, as compared to $241 million in 2003 and $250 review our asset allocation and rebalance our portfolio when million in 2002, with the remaining credits generated allocated considered appropriate. Given market conditions, we believe to third party partners. Outside firms assist us in assuring we 9.0% is a reasonable long-term rate of return on our plan assets.

operate in accordance with our private letter rulings and within the We will continue to evaluate our actuarial assumptions, including parameters of the law, as well as calculating the value of tax credits. our expected rate of return, at least annually.

Goodwill We base our determination of the expected return on qualified Certain of our business units have goodwill resulting from purchase plan assets on a market-related valuation of assets, which reduces business combinations (Notes 2 and 16). In accordance with SFAS year-to-year volatility. This market-related valuation recognizes No. 142, "Goodwill and Other IntangibleAssets," each of our changes in fair value in a systematic manner over a three-year 34 2004 annual report 1I

period. Because of this method, the future value of assets will be pension plans in 2005. At the discretion of management, impacted as previously deferred gains or losses are recorded. We we anticipate making a $0to $40 million contribution to our have unrecognized net gains due to the recent favorable perform- postretirement plans in 2005.

ance of the financial markets. As of December 31, 2004, we had In December 2003, the Medicare Prescription Drug, Improvement

$63 million of cumulative gains that remain to be recognized in and Modernization Act was signed into law. This Act provides for the calculation of the market-related value of assets. a federal subsidy to sponsors of retiree health care benefit plans The discount rate that we utilize for determining future pension that provide a benefit that is at least actuarially equivalent to and postretirement benefit obligations is based on a review of the benefit established by law. The effects of the subsidy on the bonds that receive one of the two highest ratings given by a recog-' measurement of net periodic postretirement benefit costs reduced nized rating agency. The discount rate determined on this basis has costs by $16 million in 2004.

decreased from 6.25% at December 31, 2003 to 6.0% at December See Note 14 - Retirement Benefits and Trusteed Assets for a 31, 2004. Due to recent financial market performance, lower further discussion of our pension and postretirement benefit plans.

discount rates and increased health care trend rates, we estimate that our 2005 pension costs will approximate $96 million compared Allowance for Doubtful Accounts to $81 million in 2004 and our 2005 postretirement benefit costs We establish an allowance for doubtful accounts based upon will approximate $155 million compared to $125 million in 2004. factors surrounding the credit risk of specific customers, In the last several years we have made modifications to the pension historical trends; economic conditions, age of receivables and and postretirement benefit plans to mitigate the earnings impact other information. Higher customer bills due to increased gas of higher costs. Future actual pension and postretirement benefit prices,the lack of adequate levels of assistance for low-income costs will depend on future investment performance, changes in customers and economic conditions have also contributed to the future discount rates and various other factors related to plan increase in past due receivables. As'a result of these factors, our design. Additionally, future pension costs for Detroit Edison will be allowance for doubtful accounts increased in 2003 and 2004.

affected by a pension tracking mechanism, which was authorized We believe the allowance for doubtful accounts is based on

by the MPSC in its November 2004 rate order. The tracking mecha- reasonable estimates. However, failure to make continued nism provides for the recovery or refunding of pension costs above progress' in collecting our past due receivables would or below the amount reflected in Detroit Edison's base rates. unfavorably affect operating results and cash flow.

Lowering the expected long-term rate of return on our plan Legal and Tax Reserves assets by 1.0% would have increased our 2004 qualified pension We are involved in legal and tax proceedings, claims and litigation costs by approximately $24 million. Lowering the discount arising in the ordinary course of business. We regularly assess rate and the salary increase assumptions by 1.0% would have, increased our pension costs for 2004 by approximately $8million. our liabilities and contingencies in connection with asserted or potential matters, and establish reserves when appropriate.

Lowering the health care cost trend assumptions by 1.0% would Legal reserves are based upon management's assessment of have decreased our postretirement benefit service and interest costs for 2004 by approximately $17 million. pending and threatened legal proceedings against the Company.

Tax reserves are based upon management's assessment of The market value of our pension and postretirement benefit plan potential adjustments to tax positions taken. We regularly review assets has been affected by the financial markets. The value of our, ongoing tax audits and prior audit experience, in addition to current plan assets increased from $2.4 billion at December 31, 2002 to tax and accounting authority in assessing potential adjustments.

$2.9 billion at December 31, 2003. The value at December 31, 2004 increased to $3.3 billion. The investment performance returns and ENVIRONMENTAL MATTERS declining discount rates required us to recognize an additional Protecting the environment, as well as correcting past minimum pension liability, an intangible asset and an entry to environmental damage, continues to be a focus of state and other comprehensive loss (shareholders' equity) at December federal regulators. Legislation and/or rulemaking could further 2002, 2003 and 2004. The additional minimum pension liability. impact'the electric utility industry including Detroit Edison.

and related accounting entries will be reversed on the balance The Envir6nmental Protection Agency (EPA) and the Michigan sheet in future periods if the fair value of plan assets exceeds the Department of Environmental Quality have aggressive programs accumulated pension benefit obligations. The recording of the , to clean-up contaminated property.

minimum pension liability does not affect net income or cash flow. Air - The EPA ozone transport and acid rain regulations and Pension and postretirement costs and pension cash funding final new air quality'standards relating to ozone and particulate requirements may increase in future years without substantial air pollution Wvill continue to impact us. Detroit Edison has spent returns in the financial markets. We made a $35 million cash approximately $580 million through December 2004 and estimates contribution to the pension plan in 2002, a $222 million cash that it will spend up to $100 million in 2005. Detroit Edison contribution in 2003 and a $170 million contribution to our estimates it will incur fromn $700 million to $1.3 billion of pension plan in the form of DTE Energy common stock in 2004. additional future capital expenditures over the next five to We also contributed $33 million to the postretirement plans in eight years to satisfy both existing and proposed new control 2002 and contributed $80 million to the postretirement plans in requirements. Recovery of costs to be incurred through December

- 2004. We did not contribute to the postretirement plans in 2003. 2004 was provided for in our November 2004 electric rate order.

We do not anticipate making a contribution to our qualified See Note 4 - Regulatory Matters.

2004 annual report 35

The EPA has initiated enforcement actions against several major DTE ENERGY OPERATING SYSTEM AND DTE2 electric utilities citing violations of the Clean Air Act, asserting that older, coal-fired power plants have been modified in ways that During 2002, we adopted the DTE Energy Operating System, would require them to comply with the more restrictive "new which is the application of tools and operating practices that source" provisions of the Clean Air Act. Detroit Edison received have resulted in operating efficiencies, inventory reductions and and responded to information requests from the EPA on this improvements in technology systems, among other enhancements.

subject. The EPA has not initiated proceedings against Detroit Operation and maintenance expenses benefited from our h

Edison. The United States District Court for the Southern District Company-wide initiative to pursue cost efficiencies and enhance of Ohio Eastern Division issued a decision in August 2003 finding operating performance. We expect continued cost containment Ohio Edison Company in violation of the new source provisions of efforts and process improvements.

the Clean Air Act. If the Court's decision is upheld, the electric In 2003, we began the implementation of DTE2, a Company-wide utility industry could be required to invest substantial amounts on initiative to improve existing processes and to implement new pollution control equipment. During the same month, however, a core information systems including, finance, human resources, district court in a different division rendered a conflicting decision supply chain and work management. We expect to incrementally on the matter. On October 27, 2003, the EPA promulgated new spend approximately $150 million to $175 million over the life of rules, effective December 26, 2003, allowing repair, replacement or the project. We expect the benefits to outweigh this investment upgrade of production equipment without triggering source primarily from lower costs, faster business cycles, repeatable and requirement controls if the cost of the parts and repairs do not optimized processes, enhanced internal controls, improvements in exceed 20% of the replacement value of the equipment being inventory management and reductions in system support costs.

upgraded. Such repairs will be considered routine maintenance, We are in process of launching the first phase of our multi-year however any changes in emissions would be subject to existing DTE2 project. Although our implementation plan includes pollution permit limits and other state and federal programs for detailed testing and contingency arrangements to ensure a smooth pollutants. Several states and environmental organizations have and successful transition, wve can provide no assurance that challenged these regulations and, on December 24, 2003, were complications will not arise that could interrupt our operations.

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 NEW ACCOUNTING PRONOUNCEMENTS of this issue upon Detroit Edison. See Note 2 - New Accounting Pronouncements for discussion of Water - In July 2004, the EPA published final regulations new pronouncements.

establishing performance standards for reducing fish loss at FAIR VALUE OF CONTRACTS existing power plant cooling water intake structures. These The following disclosures are voluntary and we believe provide regulations require individual facility studies, and possible intake enhanced transparency of the derivative activities and position of modifications that will be determined and implemented over the our Energy Trading &Marketing segment and our other businesses.

next five to seven years. It is estimated that we will incur up to

$50 million in additional capital expenditures for Detroit Edison. We use the criteria in Statement of Financial Accounting Standards No. 133, 'AccountingforDerivative Instruments and ContaminatedSites - DTE Enterprises Inc. (MichCon and Citizens) HedgingActivities," as amended and interpreted, to determine if owns, or previously owned, 18 former manufactured gas plant certain contracts must be accounted for as derivative instruments.

(MGP) sites. During the mid-1980's, Enterprises conducted The rules for determining whether a contract meets the criteria preliminary environmental investigations at former MGP sites, for derivative accounting are numerous and complex. Moreover, and some contamination related to the by-products of gas significant judgment is required to determine whether a contract manufacturing was discovered at each site. Enterprises employed requires derivative accounting, and similar contracts can some-outside consultants to evaluate remediation alternatives and times be accounted for differently. If a contract is accounted associated costs for these sites. As a result of these studies, for as a derivative instrument, it is recorded in the financial Enterprises accrued a liability and a corresponding regulatory statements as Assets or Liabilities from Risk Management and asset of $24 million. At December 31, 2004, the reserve balance Trading Activity, at the fair value of the contract. The recorded was $24 million of which $4.5 million was classified as current. fair value of the contract is then adjusted quarterly to reflect Our current estimates indicate that the previously accrued amounts any change in the fair value of the contract, a practice known are adequate to cover the costs of required remedial actions. as mark-to-market (MTM) accounting.

Detroit Edison conducted remedial investigations at Fair value represents the amount at which willing parties would contaminated sites, including two former MGP sites, the area transact an arms-length transaction. To determine the fair value surrounding an ash landfill and several underground and of contracts that are accounted for as derivative instruments, we aboveground storage tank locations. The findings of these use a combination of quoted market prices and mathematical valu-investigations indicated that the estimated cost to remediate ation models. Valuation models require various inputs, including these sites is approximately $8million, which is expected to forward prices, volatility, interest rates, and exercise periods.

be incurred over the next several years. As a result of the investigation, Detroit Edison accrued approximately $8million Contracts we typically classify as derivative instruments are power liability during 2004. and gas forwards, futures, options and swaps, as well as foreign currency contracts. Items we do not generally account for as 36 2004 annual report 11

derivatives (and which are therefore excluded from the following * 'Economic Hedges" represents derivative activity associated tables) include gas inventory, gas storage and transportation with assets owned and contracted by DTE Energy, including arrangements, full-requirements power contracts and gas and oil forward sales of gas production and trades associated with reserves. As subsequently discussed, we have fully reserved the owned transportation and storage capacity. Changes in the value of derivative contracts beyond the liquid trading timeframe value of derivatives in this category economically offset changes and which therefore do not impact income. in the value of underlying non-derivative positions, which do not The subsequent tables contain the following four categories qualify for fair value accounting. The difference in accounting represented by their operating characteristics and key risks. treatment of derivatives in this category and the underlying

"Proprietary Trading" represents derivative activity transacted non-derivative positions can result in significant earnings volatility as discussed in more detail in the preceding Results with the intent of taking a view, capturing market price of Operations section.

changes, or putting capital at risk. This activity is speculative in nature as opposed to hedging an existing exposure. * "Gas Production" represents derivative activity associated with our Michigan gas reserves. Asubstantial portion of the

"Structured Contracts" represents derivative activity transacted price risk associated with these reserves has been mitigated with the intent to capture profits by originating substantially through 2013. Changes in the value of the hedges are recorded hedged positions with wholesale energy marketers, utilities, as Liabilities from Risk Management and Trading with an offset retail aggregators and alternative energy suppliers. Although transactions are generally executed with a buyer and seller in other comprehensive income to the extent that the hedges are deemed effective. The amounts shown in the following simultaneously, some positions remain open until a suitable tables exclude the value of the underlying gas reserves and offsetting transaction can be executed.

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) - (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 Credit Risk As previously discussed, we fully reserve all unrealized gains Bankruptcies and losses related to periods beyond the liquid trading timeframe. We purchase and sell electricity, gas, coal, coke and other Our intent is to recognize MITM activity only when pricing energy products from and to numerous companies operating data is obtained from active quotes and published indexes. in the steel, automotive, energy, retail and other industries.

Actively quoted and published indexes include exchange traded Anumber of customers have filed for bankruptcy protection (i.e., NYNIEX) and over-the-counter (OTO) positions for which under Chapter 11 of the U.S. Bankruptcy Code. We have broker quotes are available. The NYMEX has currently quoted negotiated or are currently involved in negotiations with each prices for the next 72 months. Although broker quotes for gas of the companies, or their successor companies, that have filed and power are generally available for 18 and 24 months into the for bankruptcy protection. W'e regularly review contingent future, respectively, we fully reserve all unrealized gains and matters relating to purchase and sale contracts and record losses related to periods beyond the liquid trading timeframe provisions for amounts considered at risk of probable loss.

and which therefore do not impact income. Wre believe our accrued amounts are adequate for probable The table below shows the maturity of our MITM positions: losses. The final resolution of these matters is not expected to have a material effect on our financial statements in the iI Source of Fair Value 2008 Total and Fair period they are resolved.

(inMillions) 2005 2006 2007 Beyond Value We engage in business with customers that are non-investment Proprietary Trading $ 3 $ (2) $ 2 $ - $ 3 grade. We closely monitor the credit ratings of these customers Structured Contracts 17 4 1 1 23 and, when deemed necessary, we request collateral or guarantees Economic Hedges (55) (27) (16) - (98) from such customers to secure their obligations.

Total Energy Marketing Energy Trading & CoEnergy Portfolio

& Trading (35) (25) (13) 1 (72)

We utilize both external and internally generated credit Other Non-Trading Activities (38) (51) (11) - (100) assessments when determining the credit quality of our trading counterparties. The following table displays the credit quality Total $ (73) S (76) $ (24) $ 1 $(172) of our trading counterparties as of December 31, 2004:

Credit Exposure Quantitative and Qualitative before Cash Cash Net Credit Disclosures About Market Risk (inMillions) Collateral Collateral Exposure Commodity Price Risk Investment Grade (1)

DTE Energy has commodity price risk arising from market A- and Greater $ 234 $ (2) $ 232 price fluctuations in conjunction with the anticipated purchase BBB+ and BBB 191 (18) 173 of electricity to meet its obligations during periods of peak BBB- 17 - 17 demand. Wte also are exposed to the risk of market price Total Investment Grade 442 (20) 422 fluctuations on gas sale and purchase contracts, gas production Non-investment grade (2) 15 - 15 and gas inventories. To limit our exposure to commodity price Internally Rated fluctuations, we have entered into a series of electricity and gas -investmentgrade13) 78 (1) 77 futures, forwards, option and swap contracts. Commodity price Internally Rated risk associated with our electric and gas utilities is limited due - non-investment grade (4) 2 - 2 to the PSCR and GCR mechanisms (Note 1). Total S 537 S (21) $ 516 Our Energy Services and Biomass businesses are also subject (11This category includes counterparties with minimum credit ratings of to crude oil price risk. As previously discussed, the Section 29 Baa3 assigned by Moody's Investors Service (Moody's) and BBB- assigned by Standard & Poors Rating Group (Standard & Poors). The five largest tax credits generated by DTE Energys synfuel and biomass counterparty exposures combined for this category represented 28% of the operations are subject to phase out if domestic crude oil prices total gross credit exposure.

reach certain levels. (2)This category includes counterparties with credit ratings that are below See Note 12 - Financial and Other Derivative Instruments investment grade. The five largest counterparty exposures combined for for further discussion. 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.

38 2004 annual report it

Interest Rate Risk Summary of Sensitivity Analysis DTE Energy is subject to interest rate risk in connection with We performed a sensitivity analysis to calculate the fair values of the issuance of debt and preferred securities. In order to our commodity contracts, long-term debt instruments and foreign manage interest costs, we use treasury locks and interest rate currency forward contracts. The sensitivity analysis involved swap agreements. Our exposure to interest rate risk arises increasing and decreasing forward rates at December 31, 2004 by primarily from changes in U.S. Treasury rates, commercial a hypothetical 10% and calculating the resulting change in the fair paper rates and London Inter-Bank Offered Rates (LIBOR). values of the commodity, debt and foreign currency agreements.

As of December 31, 2004, the Company has a floating rate debt to The results of the sensitivity analysis calculations follow:

total debt ratio of approximately 11% (excluding securitized debt).

Activity Assuming a 10%/6Assuming a10% Change in the Foreign Currency Risk an Millions) increase inrates decrease inrates fair value of DTE Energy has foreign currency exchange risk arising from Gas Contracts $ (18) $ 18 Commodity contracts market price fluctuations associated with fixed priced contracts. Power Contracts $ 1 $ (2) Commodity contracts These contracts are denominated in Canadian dollars and Oil Contracts $ 15 $ (8) Commodity options are primarily for the purchase and sale of power as well as Interest Rate Risk $ (311) $ 325 Long-term debt for long-term transportation capacity. To limit our exposure Foreign Currency Risk $ - $ - Forward contracts to foreign currency fluctuations, we have entered into a series of currency forward contracts through 2008.;

report of management's responsibility:

for financial statements and internal control over financial reporting FinancialStatements DTE Energy Company management' assessed the effectiveness We have reviewed this annual report to shareholders, and based of the company's internal control over on our knowledge, this annual report does not contain any untrue' financial reporting as of December 31, statement of a material fact or omit to state a material fact 2004. In making this assessment, it used the necessary to make the statements made, in light of the circum-criteria set forth by the Committee of Sponsoring Organizations stances under which such statements were made, not misleading of the Treadway Commission (COSO) in InternalControl-with respect to the period covered by this annual report. Also, IntegratedFramework. -Based on our assessment, management based on our knowledge, the financial statemeiits, and other finran-believes that, as of December 31, 2004, DTE Energy Company's cial information included in this annual report, fairly present in all internal control over financial reporting was effective based on material respects the financial condition, results of opertions and those criteria.

cash flows of DTE Energy as of, and for, the periods presented.

Our management's assessment of the effectiveness of the Internal Control Over FinancialReporting company's internal control over financial reporting has been The management of DTE Energy Company is responsible for audited by DTE Energy's independent auditors, as stated in establishing and maintaining adequate internal control over their report which is included herein.

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. Anthony F.Early Jr.

Chairman, Chief Executive and Chief Operating Officer 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 David E. Meador any evaluation of the effectiveness to future periods are subject to Executive Vice President and Chief Financial Officer 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.

2004 annual report 39

reports of independent registered public accounting firm To the Board of Directors and Shareholders of DTE Energy Company: principles, and that receipts and expenditures of the company are being We have audited management's assessment, included in the accompanying made only in accordance with authorizations of management and directors Management's report on Internal Control Over Financial Reporting, that of the company; and (3) provide reasonable assurance regarding prevention DTE Energy Company and subsidiaries (the "Company") maintained effective or timely detection of unauthorized acquisition, use, or disposition of internal control over financial reporting as of December 31, 2004, based on the company's assets that could have a material effect on the criteria established inInteralControl- IntegratedPramework issued by financial statements.

the Committee of Sponsoring Organizations ofthe Theadway Commission. Because of the inherent limitations of internal control over financial The Companrs management is responsible for maintaining effective internal reporting, including the possibility of collusion or improper management control over financial reporting and for its assessment of the effectiveness override of controls, material misstatements due to error or fraud may of internal control over financial reporting. Our responsibility isto express an not be prevented or detected on a timely basis. Also, projections of any opinion on management's assessment and an opinion on the effectiveness of evaluation of the effectiveness of the internal control over financial the Companys internal control over financial reporting based on our audit. reporting to future periods are subject to the risk that the controls may We conducted our audit in accordance with the standards of the Public become inadequate because of changes in conditions, or that the degree Company Accounting Oversight Board (United States). Those standards of compliance with the policies or procedures may deteriorate.

require that we plan and perform the audit to obtain reasonable assurance In our opinion, management's assessment that the Company maintained about whether effective internal control over financial reporting was effective internal control over financial reporting as of December 31, 2004, maintained in all material respects. Our audit included obtaining an is fairly stated, in all material respects, based on the criteria established in understanding of internal control over financial reporting, evaluating Internul Control- IntegratedFramework issued by the Committee of management's assessment, testing and evaluating the design and operating Sponsoring Organizations of the Treadway Commission. Also in our opinion, effectiveness of internal control, and performing such other procedures as the Company maintained, in all material respects, effective internal control we considered necessary inthe circumstances. We believe that our audit over financial reporting as of December 31, 2004, based on the criteria provides a reasonable basis for our opinions. established in Internal Control - IntegratedFrameworkissued by the Acompanys internal control over financial reporting is a process designed Committee of Sponsoring Organizations of the Treadway Commission.

by, or under the supervision of, the company's principal executive and We have also audited, in accordance with the standards of the Public principal financial officers, or persons performing similar functions, and Company Accounting Oversight Board (United States), the consolidated effected by the company's board of directors, management, and other financial statements of the Company as of December 31, 2004 and for personnel to provide reasonable assurance regarding the reliability of the year then ended; and our report dated March 15, 2005 expressed an financial reporting and the preparation of financial statements for external unqualified opinion on those consolidated financial statements.

purposes in accordance with generally accepted accounting principles.

Acompany'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 Deloitte.

Deloitte &Touche LLP that transactions are recorded as necessary to permit preparation of Detroit, Michigan Suite 900, 600 Renaissance Center financial statements in accordance with generally accepted accounting March 15, 2005 Detroit, Michigan 48243-1704 To the Board of Directors and Shareholders of DTE Energy Company. ended December 31, 2004 in conformity with accounting principles We have audited the consolidated statement of financial position of generally accepted in the United States of America.

DTE Energy Company and subsidiaries (the "Company") as of As discussed in Note 2to the consolidated financial statements, in connec-December 31,2004 and 2003, and the related consolidated statements tion with the required adoption of certain new accounting principles, in 2003 of operations, cash flows, and changes in shareholders' equity and the Company changed its method of accounting for asset retirement obliga-comprehensive income for each of the three years in the period ended tions, energy trading contracts and gas inventories and in 2002 the Company December 31,2004. These financial statements are the responsibility of changed its method of accounting for goodwill and energy trading contracts.

the Company's management Our responsibility is to express an opinion We have also audited, inaccordance with the standards of the Public on the consolidated financial statements based on our audits. Company Accounting Oversight Board (United States), the effectiveness We conducted our audits in accordance with the standards of the Public of the Company's internal control over financial reporting as of December Company Accounting Oversight Board (United States). Those standards 31,2004, based on the criteria established in InternalControl- Integrated require that we plan and perform the audit to obtain reasonable assurance Framework issued by the Committee of Sponsoring Organizations of about whether the financial statements are free of material misstatement. the Treadway Commission and our report dated March 15,2005 expressed An audit includes examining, on a test basis, evidence supporting the an unqualified opinion on management's assessment of the effectiveness amounts and disclosures in the financial statements. An audit also includes of the Company's internal control over financial reporting and an assessing the accounting principles used and significant estimates made by unqualified opinion on the effectiveness of the Company's internal management, as well as evaluating the overall financial statement presenta- control over financial reporting, 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 Deloitte.

Deloitte & Touche LLP subsidiaries at December 31, 2004 and 2003, and the results of their Detroit, Michigan Suite 900, 600 Renaissance Center operations and their cash flows for each of the three years in the period March 15,2005 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 (Note8)

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 $ 56,- $ 54 Restricted cash (Note 1) 126-, 131 Accounts receivable Customer (less allowance for doubtful accounts of $129 and $99, respectively) 880- 877 Accrued unbilled revenues 378 316 Other 383 338 Inventories Fuel and gas 0: 509: 467 Materials and supplies I D -:, ~159 162 Assets from risk management and trading activities - ' ;,..' 20 186 Other - -S :7 :' -' 209 181 2,996 2,712 Investments Nuclear decommissioning trust funds .590 518 I 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 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 inassets 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 injoint ventures (36) (34) (21)

Proceeds from sale of interests insynfuel 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) (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) - - (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 6, 7 1, 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 inunrealized 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

Fuel Pansportationand Marketing, primarily consisting of coal transportation and marketing, gas pipelines and storage, Corporate Structure and energy marketing and trading operations; and DTE Energy is an exempt holding company under the Corporate& Other, primarily consisting of corporate support Public Utility Holding Company Act of 1935 and owns the functions and certain energy technology investments.

following businesses:

References in this report to "we," "us," "our" or "Company" are to

'7

The Detroit Edison Company DTE Energy and its subsidiaries, collectively.

(Detroit Edison), an electric utility engaged in the generation, purchase, Principles of Consolidation distribution and sale of electric WVe consolidate all majority owned subsidiaries and investments energy to 2.1 million customers in in entities in which we have controlling influence. Non-majority southeast Michigan; owned investments are accounted for using the equity method

Michigan Consolidated Gas Company when the company is able to influence the operating policies of (MlichCon), a natural gas utility the investee. Non-majority owned investments include investments 9 .W engaged in the purchase, storage, in limited liability companies, partnerships or joint ventures.

transmission and distribution and When we do not influence the operating policies of an investee, sale of natural gas to 1.2 million the cost method is used. We eliminate all intercompany balances customers throughout Michigan; and and transactions.

Other non-utility subsidiaries engaged in energy marketing and For entities that are considered variable interest entities, trading, energy services and various other electricity, coal and wve apply the provisions of Financial Accounting Standards gas related businesses. Board (FASB) Interpretation No. (FIN) 46-R, "Consolidationof Detroit Edison and MichCon are regulated by the Michigan VariableInterestEntities, an InterpretationofARB No. 51."

Public Service Commission (MPSC). The Federal Energy For a detailed discussion of FIN 46-R, see Note 2 - New Regulatory Commission (FERC) regulates certain activities of Accounting Pronouncements.

Detroit Edison's business as well as various other aspects of Basis of Presentation businesses under DTE Energy. In addition, we are regulated The accompanying consolidated financial statements are prepared by other federal and state regulatory agencies including the using accounting principles generally accepted in the United States Nuclear Regulatory Commission (NRC) and the Environmental of America. These accounting principles require us to use estimates Protection Agency, among others. and assumptions that impact reported amounts of assets, liabilities, Segments realigned- Through 2004, we operated our businesses revenues and expenses, and the disclosure of contingent assets and through three strategic business units (Energy Resources, Energy liabilities. Actual results may differ from our estimates.

Distribution and Energy Gas). Each business unit had utility and Prior to December 2004, DTE Energy did not eliminate amounts, non-utility operations. The balance of our business consisted of principally within Other Income and Other Deductions, resulting Corporate &Other. See Note 16 for further discussion. In 2005, wve from certain intercompany transactions. The amounts of the expect to realign our business units to strengthen the Company's transactions are immaterial and had no effect on net income.

focus on customer relationships and growth within our non-utility Previously reported prior period amounts have been adjusted to businesses. Based on this structure, wve will set strategic goals, eliminate those intercompany transactions and are now consistent allocate resources and evaluate performance. Beginning with the with the current year's presentation. We reclassified certain other first quarter of 2005, we expect to report our segment information prior year balances to match the current year's financial state-based on the following realignment: ment presentation.

Electric Utility, consisting of Detroit Edison; Revenues

Gas Utiliti primarily consisting of MichCon; Revenues from the sale and delivery of electricity, and the sale,

Non-utility Operations delivery and storage of natural gas are recognized as services are

Power and IndustrialProjects, primarily consisting of synfuel provided. Detroit Edison and MichCon record revenues for electric projects, on-site energy services, steel-related projects, power and gas provided but unbilled at the end of each month.

generation with services, and waste coal recovery operations; Detroit Edison's accrued revenues include a component for the

Unconventional Gas Production, primarily consisting of gas cost of power sold that is recoverable through the Power Supply production and coal bed methane operations; Cost Recovery (PSCR) mechanism. MichCon's accrued revenues include a component for the cost of gas sold that is recoverable 46 2004 annual report 11

through the Gas Cost Recovery (GCR) mechanism. Annual Cash Equivalents and Restricted Cash PSCR and GCR proceedings before the MIPSC permit Detroit Cash and cash equivalents include cash on hand, cash in Edison and MlichCon to recover prudent and reasonable supply banks and temporary investments purchased with remaining costs. Any overcollection or undercollection of costs, including maturities of three months or less. Restricted cash consists of interest, will be reflected in future rates. Prior to 2004, Detroit funds held to satisfy requirements of certain debt and partnership Edison's retail rates were frozen under Public Act (PA) 141. See operating agreements. Restricted cash is classified as a current Note 4 for further discussion. Accordingly, Detroit Edison did not asset as all restricted cash is designated for interest and principal accrue revenues under the PSCR mechanism prior to 2004. payments due within one year.

Non-utility businesses recognize revenues as services are provided Inventories and products are delivered. Our Energy Mlarketing &Trading seg- We value fuel inventory and materials and supplies at average cost.

ment records in revenues net unrealized derivative gains and losses Gas inventory at MichCon is determined using the last-in, first-out on energy trading contracts, including those to be physically settled. (LIFO) method. At December 31, 2004, the replacement cost of gas remaining in storage exceeded the $89 million LIFO cost by $330 mil-Gains from Sale of Interests in lion. At December 31, 2003, the replacement cost of gas remaining in Synthetic Fuel Facilities storage exceeded the $117 million LIFO cost by $251 million. During Through December 2004, we have sold majority interests in eight 2004, AlichCon liquidated 5.7 billion cubic feet of prior years' LIFO lay-of our nine synthetic fuel production plants, representing approxi- ers. The liquidation benefited 2004 cost of gas by approximately $7 mil-mately 92% of our total production capacity. Proceeds from the lion, but had no impact on earnings as a result of the GCR mechanism.

sales are contingent upon production levels and the value of Our Energy Marketing &Trading segment uses the average cost Section 29 tax credits. Section 29 tax credits are subject to phase method for its gas in inventory.

out if domestic crude oil prices reach certain levels. See Note 13 Property, Retirement and Maintenance, and for further discussion. We recognize gains from the sale of interests Depreciation and Depletion in the synfuel facilities as synfuel is produced and sold, and when Summary of property by classification as of December 31:

there is persuasive evidence that the sales proceeds have become fixed or determinable and collectibility is reasonably assured. tin Millions) 2004 2003 We have recorded gains from the sale of interests in synthetic Property, Plant and Equipment fuel facilities totaling $219 million, $83 million and $40 million Electric Utility during 2004, 2003 and 2002, respectively.

Generation $ 7.100 '$ 6,938 Distribution 5,831 5,733 Until the gain recognition criteria are met, gains from selling Total Electric Utility . IZ 2931 ' 12,671 .

interests in synfuel facilities will be deferred. It is possible that Gas Utility Distribution .. : 2020*

Z ,9 gains will be deferred in the first, second and/or third quarters of each year until there is persuasive evidence that no tax credit Storage '221 224 Other - 883 855 phase out Nvill occur for the applicable calendar year. This could Total Gas Utility

3,124 3,040 result in shifting earnings from earlier quarters to later quarters Energy Services of a calendar year. Coal Based Fuels X::.,6514 652 On-Site Energy ..193 180 Comprehensive Income Merchant Generation . :174 229 We comply with Statement of Financial Accounting Standards Other 8 13 (SFAS) No. 130, "Reporting ComprehensiveIncome," that Total Energy Services 1,026' 1,074 established standards for reporting comprehensive income. Other Non-utility and Other 930. 894 SFAS No. 130 defines comprehensive income as the change in Total Property, Plant and Equipment -18.011' 17,679 common shareholders' equity during a period from transactions Less Accumulated Depreciation and Depletion Electric Utility and events from non-owner sources, including net income. Generation i3;i 7) -(3,231)

As shown in the following table, amounts recorded to other Distribution (2,077) (2,108) comprehensive income (OCI) at December 31, 2004 include: Total Electric Utility ;.(5,354) (5,339) unrealized gains and losses from derivatives accounted for as Gas Utility cash flow hedges under SFAS No. 133, 'Accountingfor Derivative Distribution (845) (798)

Instruments and HedgingActivities;" unrealized gains and losses Storage (100) (102) on available for sale securities under SFAS No. 115, 'Accounting Other .-- (448) (432)

Total Gas Utility 5' (1,393) (1.332) for CertainInvestments in Debt and Equity Securities;"and, Energy Services minimum pension liabilities as prescribed by SFAS No. 87, Coal Based Fuels (272) (219)

"Employers'AccountingforPensions." On-Site Energy (:-3i

55) (42)

Minimum Net Net Accumulated Merchant Generation t tit,

' {8) l (20)

Pension Unrealized Unrealized Other Other ; .,3 .:(2)

Liability Losses on Gains on Comprehensive Total Energy Services '(348) (283)

(inMillions) Adjustment Derivatives Investments 'Loss Beginning balance $ (98) $ 1851 $ 53 $ (130) Other Non-utility and Other (425) (401)

Total Accumulated Depreciation Current-period and Depletion '17,520) (7,355) change 7 (15) (20) (28) Net Property, Plant and Equipment . 10,491$ 10,324 Ending balance $ (91) $ (1l) $ 33 $ (158) 2004 annual report 47

Property is stated at cost and includes construction-related Long-Lived Assets labor, materials, overheads and an "allowance for funds used Our long-lived assets are reviewed for impairment whenever during construction" (AFUDC). The cost of properties retired, events or changes in circumstances indicate the carrying amount less salvage, at Detroit Edison and MichCon are charged to of an asset may not be recoverable. If the carrying amount of the accumulated depreciation.

asset exceeds the expected future cash flows generated by the Expenditures for maintenance and repairs are charged to expense asset, an impairment loss is recognized resulting in the asset when incurred, except for Fermi 2. Approximately $3.8 million of being written down to its estimated fair value. Assets to be expenses related to the anticipated Fermi 2 refueling outage disposed of are reported at the lower of the carrying amount scheduled for 2006 were accrued at December 31, 2004. Amounts or fair value less cost to sell.

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 Intangible Assets, Including Software Costs policy for nuclear refueling outage costs since the Fermi 2 plant Our intangible assets consist primarily of software. W'e capitalize was placed in service in 1988. This method also matches the the costs associated with computer software we develop or regulatory recovery of these costs in rates set by the AIPSC. obtain for use in our business. We amortize intangible assets We base depreciation provisions for utility property at Detroit on a straight-line basis over expected periods of benefit.

Edison and MichCon on straight-line and units of production Intangible assets amortization expense was $43 million in 2004, rates approved by the MPSC. The composite depreciation $40 million in 2003 and $46 million in 2002. The gross carrying rate for Detroit Edison was 3.4% in 2004, 2003 and 2002. amount and accumulated amortization of intangible assets The composite depreciation rate for MfichCon was 3.6%, 3.5%, at December 31, 2004 were $445 million and $151 million, and 3.6% in 2004, 2003 and 2002, respectively. respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2003 were The average estimated useful life for each class of utility property,

$537 million and $303 million, respectively. Amortization plant and equipment as of December 31, 2004 follows:

expense of intangible assets is estimated to be $40 million Estimated Useful lives inYears annually for 2005 through 2009.

Utility Generation Distribution_ Transmission-_

Excise and Sales Taxes Electric 39 37 -

Gas N/A 26 28 We record the billing of excise and sales taxes as receivable with an offsetting payable to the applicable taxing authority, with no Non-utility property is depreciated over its estimated useful life using impact on the consolidated statement of operations.

straight-line, declining-balance or units-of-production methods.

Deferred Debt Costs We credit depreciation, depletion and amortization expense when we establish regulatory assets for stranded costs related to the electric The costs related to the issuance of long-term debt are deferred Customer Choice program and deferred environmental expenditures. and amortized over the life of each debt issue. In accordance with MPSC regulations applicable to our electric and gas utilities, Gas Production the unamortized discount, premium and expense related to debt We follow the successful efforts method of accounting for redeemed with a refinancing are amortized over the life of the investments in gas properties. Under this method of accounting, replacement issue. Discount, premium and expense on early all property acquisition costs and costs of exploratory and redemptions of debt associated with non-utility operations are development wells are capitalized when incurred, pending charged to earnings.

determination of whether the well has found proved reserves. Insured and Uninsured Risks If an exploratory well has not found proved reserves, the costs of drilling the well are expensed. The costs of development We have a comprehensive insurance program in place to provide wells are capitalized, whether productive or nonproductive. coverage for various types of risks. Our insurance policies cover Geological and geophysical costs on exploratory prospects and risk of loss from various events, including property damage, the costs of carrying and retaining unproved properties are general liability, workers' compensation, auto liability and expensed as incurred. An impairment loss is recorded to directors' and officers' liability.

the extent that capitalized costs of unproved properties, on a Under our risk management policy, we self-insure portions of property-by-property basis, are considered not to be realizable. certain risks up to specified limits, depending on the type of An impairment loss is recorded if the net capitalized costs exposure. We periodically review our insurance coverage. During of proved gas properties exceed the aggregate related 2003, we reviewed our process for estimating and recognizing undiscounted future net revenues. Depreciation, depletion reserves for self-insured risks. As a result of this review, we and amortization of proved gas properties are determined revised the process for estimating liabilities under our self-insured using the units-of-production method. 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

Consolidated Statement of Cash Flows Stock-Based Compensation A detailed analysis of the changes in assets and liabilities that are We have a stock-based employee compensation plan, which is reported in the consolidated statement of cash flows follows:

described in Note 15. The plan permits the awarding of various (inMilrions) 2004 2003 2002 stock awards, including options, restricted stock and performance Changes inAssets and Liabilities, shares. We account for stock awards under the plan under the Exclusive of Changes Shown Separately recognition and measurement principles of Accounting Principles Accounts receivable, net 73 $ (50) S (129)

Board (APB) Opinion No. 25, "AccountingforStock Issued to Accrued unbilled receivable (62) (20) (54)

Employees." No compensation cost related to stock options is Accrued GCR revenue (35) 29 (5) reflected in earnings, as all options granted had an exercise price Inventories (40) (61) (71) equal to the market value of the underlying common stock on the Accrued/Prepaid Pensions 88 (196) (10) date of grant. The recognition provisions under SFAS No. 123, Accounts payable 266 (21) 66 "Accountingfor Stock-Based Compensation,"require the recording Accrued PSCR refund 112 of compensation expense for stock options equal to their fair value Exchange gas payable (43) 90 9 at date of grant as determined using an option pricing model. The Income taxes payable (170) 135 (8) following table illustrates the effect on net income and earnings per General taxes (14) (12) (36) share if we had recorded compensation expense for options granted Risk management and trading activities .(64) 127 69 under the fair value recognition provisions of SFAS No. 123.

Postretirement obligation 299 112 77 knMilionst except pershare amounts) -2004 2003 2002 Other (131) 39 (37)

Net Income As Reported $ 431 $ 521 $ 632 RS 9$ 172 $ (129)

Less: Total Stock-based Expense (1) (6) (7) (7)

Pro Faorma Net Income S '425 $ 514 $ 625 Supplementary cash and non-cash information for the years ended December31 were as follows:

Income Per Share Basic - as reported .$ .Z50 $ 3.11 $ 3.85 ranMiflions) 2004 2003 2002 Basic - pro forma US :.2.46 $ 3.06 $ 3.81 Cash Paid For Interest (excluding Diluted - as reported S 2.49 S 3.09 $ 3.83 interest capitalized) $ - 517 $ 552 $ 551 Diluted - pro forma S 2.45 $ 3.05 $ 3.79 Income taxes $ 203 $ 31 $ 167 (1)Expense determined using a Black-Scholes based option pricing model. Noncash Investing and Financing Activities Investments in Debt and Equity Securities Notes received from sale We generally classify investments in debt and equity securities of synfuel projects t $ 214 $ 238 $ 217 Common stock contributed as either trading or available-for-sale and have recorded such to pension plan , 170 $ - $ -

investments at market value with unrealized gains or losses Exchange of debt ..$ - $ 100 $ -

included in earnings or in other comprehensive income or Issuance of loss, respectively. Changes in the fair value of nuclear equity-linked securities $ - . $ - $ 21 decommissioning-related investments are recorded as See the following notes for other accounting policies impacting our adjustments to regulatory assets or liabilities (Note 5). financial statements:

Investment in Plug Power Note Title In 1997, we invested in Plug Power Inc., a company that designs 2 New Accounting Pronouncements and develops on-site electric fuel cell power generation systems. 4 Regulatory Matters Since Plug Power is considered a development stage company, 7 Income Taxes generally accepted accounting principles required us to record 12 Financial and Other Derivative Instruments gains and losses from Plug Power stock issuances as an adjustment 14 Retirement Benefits and Trusteed Assets to equity. Prior to November 2003, we accounted for our investment in Plug Power under the equity method of accounting. We did not NOTE-2 NEW ACCOUNTING PRONOUNCEMENTS participate in Plug Power's secondary stock offering in November Energy Trading Activities 2003 and as of December 31, 2003 we owned 14.1 million shares Under Emerging Issues Task Force (EITF) Issue No. 98-10, or approximately 19% of Plug Power's common stock. We have "AccountingforContractsInvolved in Energy Tradingand determined that we do not have the ability to exercise significant Risk Management Activities," companies were required to use influence over the operating or financial policies of Plug Power. mark-to-market accounting for contracts utilized in energy trading Accordingly, we began prospective application of the cost method activities. EITF Issue No. 98-10 was rescinded in October 2002, of accounting for our investment in Plug Power, effective November and energy trading contracts must now be reviewed to determine 2003. We record our investment at market value and account for if they meet the definition of a derivative under SFAS No. 133, unrealized gains and losses in other comprehensive income or loss. 'A ccountingforDerivative Instruments and Hedging Activities."

In May 2004, we sold 3.5 million shares of Plug Power stock and SFAS No. 133 requires all derivatives to be recognized in the state-recorded a gain of approximately $14 million, net of taxes. The sale ment of financial position as either assets or liabilities measured at reduced our ownership interest in Plug Power to 10.6 million their fair value. SFAS No. 133 also requires that changes in the fair shares, or approximately 14%.

2004 annual report 49

value of derivatives be recognized in earnings unless specific hedge accounting criteria are met. Energy trading contracts A reconciliation of the asset retirement obligation for 2004 follows:

not meeting the definition of a derivative are accounted for (inMiWAons) under settlement accounting, effective October 25, 2002 for new Asset retirement obligations atJanuary 1,2004 $ 866 contracts and effective January 1,2003 for existing contracts. Accretion 57 Derivative contracts are only marked to market to the extent that Liabilities settled (5) markets are considered highly liquid where objective, transparent Revisions in estimated cash flows (2)1 prices can be obtained. Unrealized gains and losses are fully Asset retirement obligations at December 31, 2004 $ 916 reserved for transactions that do not meet this criteria.

Additionally, inventory utilized in energy trading activities Asignificant portion of the asset retirement obligations accounted for under the fair value method of accounting as represents nuclear decommissioning liabilities, which are prescribed by Accounting Research Bulletin (ARB) No. 43 is no funded through a surcharge to electric customers over the longer permitted. Our Energy Marketing &Trading segment uses life of the Fermi 2 nuclear plant.

gas inventory in its trading operations and switched from the fair SFAS No. 143 also requires the quantification of the estimated value method to the average cost method in January 2003. cost of removal obligations, arising from other than legal Effective January 1,2003, we no longer applied EITF Issue obligations, which have been accrued through depreciation No. 98-10 to energy contracts and ARB No. 43 to gas inventory. charges. At December 31, 2003, we reclassified approximately

$655 million of previously accrued asset removal costs related to As a result of discontinuing the application of these accounting our utility operations, which had been previously netted against principles, we recorded a cumulative effect of accounting accumulated depreciation to regulatory liabilities. There is a change that reduced net income for the first quarter of generic case before the MPSC to determine the accounting and 2003 by $16 million (net of taxes of $9million).

regulatory treatment of removal costs for Michigan utilities.

Asset Retirement Obligations Consolidation of Variable Interest Entities On January 1,201)3, we adopted SFAS No. 143, 'Accountingfor In January 2003, FASB Interpretation No. (FIN) 46, Asset Retirement Obligations,"which requires the fair value of an "Consolidationof Variable InterestEntities, an Interpretation asset retirement obligation be recognized in the period in which ofAccounting ResearchBulletin(ARB) No. 51, "was issued and it is incurred. We identified a legal retirement obligation for the requires an investor with a majority of the variable interests decommissioning costs for our Fermi 1 and 2 nuclear plants. (primary beneficiary) in a variable interest entity to consolidate To a lesser extent, we have retirement obligations for our synthetic the assets, liabilities and results of operations of the entity.

fuel operations, gas production facilities, asphalt plant, gas Avariable interest entity is an entity in which the equity investors gathering facilities and various other operations. As to utility do not have controlling interests, the equity investment at risk operations, we believe that adoption of SFAS No. 143 results is insufficient to finance the entity's activities without receiving primarily in timing differences in the recognition of legal asset additional subordinated financial support from other parties, or retirement costs that we are currently recovering in rates and equity investors do not share proportionally in gains or losses.

are deferring such differences under SFAS No. 71, "Accounting In October 2003 and December 2003, the FASB issued Staff Position for the Effects of CertainTpes of Regulation."

No. FIN 46-6 and FIN 46-Revised (FIN 46-R), respectively, which As a result of adopting SFAS No. 143 on January 1,2003, we recorded clarified and replaced FIN 46 and also provided for the deferral of a plant asset of $306 million with offsetting accumulated deprecia- the effective date of FIN 46 for certain variable interest entities.

tion of $106 million, a retirement obligation liability of $815 million We have evaluated all of our equity and non-equity interests and and reversed previously recognized obligations of $377 million, have adopted all current provisions of FIN 46-R. The adoption of principally nuclear decommissioning liabilities. We also recorded a FIN 46-R did not have a material effect on our financial statements.

cumulative effect amount related to utility operations as a regulatory asset of $221 million, and a cumulative effect charge against earnings Medicare Act Accounting of $11 million (net of tax of $7million) for 2003. In December 2003, the "MedicarePrescriptionDrug, Improvement and ModernizationAct of 2003" (Medicare Act)

If a reasonable estimate of fair value cannot be made in the period was signed into law. The Medicare Act provides for a non-taxable the asset retirement obligation is incurred, such as assets with an federal subsidy to sponsors of retiree health care benefit plans indeterminate life, the liability is to be recognized when a reason-that provide a benefit that is at least "actuarially equivalent" to able estimate of fair value can be made. Generally, distribution the benefit established by law. We elected at that time to defer the assets have an indeterminate life, retirement cash flows cannot be provisions of the Medicare Act, and its impact on our accumulated determined and there is a low probability of retirement, therefore postretirement benefit obligation and net periodic postretirement no liability has been recorded for these assets. benefit cost, pending the issuance of specific authoritative The pro forma effect on earnings had SFAS No. 143 been adopted accounting guidance by the FASB.

for all periods presented would decrease reported net income and In May 2004, FASB Staff Position (FSP) No. 106-2 was issued on basic and diluted earnings per share as follows: accounting for the effects of the Medicare Act. The guidance in (in Millions) this FSP is applicable to sponsors of single-employer defined Net Basic and Diluted benefit postretirement health care plans for which (a) the Year Income Earnings per Share employer has concluded the prescription drug benefits available 2002 $ 4.8 $ .03 under the plan to some or all participants are "actuarially 50 2004 annual report equivalent" to Medicare Part Dand thus qualify for the subsidy 11

under the Medicare Act and (b) the expected subsidy will offset Detroit Edison's Steam Heating Business or reduce the employer's share of the cost of the underlying In January 2003, we sold Detroit Edison's steam heating business postretirement prescription drug coverage on which the subsidy to Thermal Ventures II, LP. Due to the continuing involvement is based. Woe believe we qualify for the subsidy under the of Detroit Edison in the steam heating business, including the Medicare Act and the expected subsidy will partially offset our commitment to purchase steam and/or electricity through 2024, share of the cost of postretirement prescription drug coverage. fund certain capital improvements and guarantee the buyer's credit In June 2004, we adopted FSP No. 106-2, retroactive to January 1, facility, we recorded a net of tax loss of approximately $14 million 2004. As a result of the adoption, our accumulated postretirement in 2003. As a result of Detroit Edison's continuing involvement, benefit obligation for the subsidy related to benefits attributed to this transaction is not considered a sale for accounting purposes.

past service was reduced by approximately $95 million and was The steam heating business had assets of $6 million at accounted for as an actuarial gain. The effects of the subsidy December 31,2002, and had net losses of $12 million in 2002.

reduced net postretirement costs by $16 million in 2004. See Note 13 - Commitments and Contingencies.

Stock Based Payments Southern Missouri Gas Company-In December 2004, the FASB issued SFAS No. 123-R, "Stock Discontinued Operation Based Payments, °which establishes the accounting for We own Southern Missouri Gas Company (SMIGC), a public utility transactions in which an entity exchanges equity instruments engaged in the distribution, transmission and sale of natural gas in for goods or services. Application of SPAS No. 123-R is required southern Missouri. In the first quarter of 2004, management approved for interim or annual periods beginning after June 16, 2005 with the marketing of SMGC for sale. As of March 31,2004, SMGC met the earlier adoption encouraged. We have completed a preliminary SFAS No. 144 criteria of an asset "held for sale," and we have reported review and estimate that the new standard will reduce reported its operating results as a discontinued operation. We recognized a earnings by approximately $5 million to $10 million per year. net of tax impairment loss of approximately $7 million in 2004, representing the write-down to fair value of the assets of SMGC, less Goodwill and Other Intangible Assets costs to sell, and the write-off of allocated goodwill. In November Effective January 1, 2002, we adopted SFAS No. 142, 'Goodwill and 2004, we entered into a definitive agreement providing for the sale Other IntangibleAssets,"whichaddresses the financial accounting of SMGC. Following receipt of regulatory approvals and resolution and reporting standards for the acquisition of intangible assets out- of other contingencies, it is anticipated that the transaction will side of a business combination and for goodwill and other intangible close in 2005. SMGC had assets of $9 million and liabilities of assets subsequent to their acquisition. This accounting standard $35 million at December 31, 2004.

requires that goodwill no longer be amortized, but reviewed at least annually for impairment. In accordance with SFAS No. 142, we NOTE-4 REGULATORY MATTERS discontinued the amortization of goodwill effective January 1,2002.

Regulation NOTE-3 DISPOSITIONS Detroit Edison and MichCon are subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to International Transmission Company - retail rates, recovery of certain costs, including the costs of Discontinued Operation generating facilities and regulatory assets, conditions of service, In February 2003, we sold International Transmission Company accounting and operating-related matters. Detroit Edison is also (ITC), our electric transmission business, for $610 million to regulated by the FERC with respect to financing authorization affiliates of Kohlberg Kravis Roberts &Co. and Timaran Capital and wholesale electric activities.

Partners, LLC. The sale generated a preliminary net of tax gain As subsequently discussed in the "Electric Industry Restructuring" of $63 million in 2003. The gain was net of transaction costs, the section, Detroit Edison's rates were frozen through 2003 and capped portion of the gain that was refundable to customers and the write for small business customers through 2004 and for residential off of approximately $44 million of allocated goodwill. The gain customers through 2005 as a result of Public Act (PA) 141. However, was lowered to $58 million in 2004 under the MPSC's November Detroit Edison was allowed to defer certain costs to be recovered 2004 final rate order that resulted in a revision of the applicable once rates could be increased, including costs incurred as a result transaction costs and customer refund. of changes in taxes, laws and other governmental actions.

As prescribed by SFAS No. 144, "Accountingfor the Impairmentor Regulatory Assets and Liabilities DisposalofLong-Lived Assets, 'we have reported the operations of Detroit Edison and MichCon apply the provisions of SFAS No. 71, ITC as a discontinued operation as shown in the following table:

'Accountingfor theEffects of Certain ltpes ofRegulation,"

(inMillions) 2003 (3) 2002 to their regulated operations.. SFAS No. 71 requires the recording Revenues (1) $ 21 $ 138 of regulatory assets and liabilities for certain transactions that Expenses (2) 13 :67 would have been treated as revenue and expense in non-regulated Operating income 8 . 71 businesses. Continued applicability of SFAS No. 71 requires that Income taxes 3 25 rates be designed to recover specific costs of providing regulated Income from discontinued operations $ 5 $ 46 services and be charged to and collected from customers. Future regulatory changes or changes in the competitive environment (1)Includes intercompany revenues of$18 million for2003 and $118 million for 2002 (2)Excludes general corporate overhead costs that were previously allocated to could result in the Company discontinuing the application of ITC in 2003 and 200Z SFAS No. 71 for some or all of its utility businesses and may require (3)Represents activity from January 1,2003 through February 28, 2003, the write-off of the portion of any regulatory asset or liability that when ITC was sold.

2004 annual report 51

was no longer probable of recovery through regulated rates. accounting principles due to the current under funded status Management believes that currently available facts support the of certain pension plans. The traditional rate setting process continued application of SFAS No. 71 to Detroit Edison and MichCon. allows for the recovery of pension costs as measured by generally The following are balances and a brief description of the accepted accounting principles. Accordingly, the minimum regulatory assets and liabilities at December 31: pension liability associated with utility operations is recoverable.

fin Millions) 2004 2003 See Notes 4 and 14.

Assets

Asset retirementobligation - Asset retirement obligations were Securitized regulatory assets $ 1,438 $ 1,527 recorded pursuant to adoption of SFAS No. 143 in 2003. These Recoverable income taxes related to obligations are primarily for Fermi 2 decommissioning costs that securitized regulatory assets $ 788 $ 837 are recovered in rates.

Recoverable minimum pension liability 605 585

Otherrecoverable income taxes - Income taxes receivable Asset retirement obligation 183 192 from Detroit Edison's customers representing the difference in Other recoverable income taxes 109 114 property-related deferred income taxes receivable and amounts Recoverable costs under PA 141 previously reflected in Detroit Edison's rates.

Net stranded costs 122 68

Net strandedcosts - PA 141 permits, after MPSC authorization, Excess capital expenditures 7 - the recovery of and a return on fixed cost deficiency associated Deferred Clean Air Act expenditures 76 54 with the electric Customer Choice program. Net stranded costs Midwest Independent System occur when fixed cost related revenues do not cover the fixed Operator charges 27 21 cost revenue requirements.

Transmission integration costs - 10

Excess capitalexpenditures - Starting in 2004, PA 141 permits, Electric Customer Choice after MPSC authorization, the recovery of and a return on capital implementation costs 95 84 expenditures that exceed a base level of depreciation expense.

Enhanced security costs 8 6 Unamortized loss on reacquired debt 63 60

Deferred CleanAirAct expenditures- PA 141 permits, after MPSC authorization, the recovery of and a return on Clean Air Deferred environmental costs 31 29 Act expenditures.

Accrued GCR revenue 55 19 Other 5 3

Midwest Independent System Operatorcharges- PA 141 2174 2,082 permits, after MPSC authorization, the recovery of and a return Less amount included incurrent assets (55) (19) on charges from a regional transmission operator such as the Midwest Independent System Operator.

$ 2,119 $2,063

Transmissionintegrationcosts - The MPSC's November 2004 Liabilities final rate order denied recovery and determined these costs to Asset removal costs $ 679 $ 655 be transaction expenses in DTE Energy's sale of ITC.

Excess securitization savings - 14

Electric Customer Choice implementation costs - PA 141 Customer refund -1997 storm 2 2 permits, after MPSC authorization, the recovery of and a return Refundable income taxes 135 146 on costs incurred associated with the implementation of the Accrued GCR potential disallowance 28 26 electric Customer Choice program.

Accrued PSCR refund 112

Enhanced security costs - PA 141 permits, after MPSC Other -3 3 authorization, the recovery of enhanced homeland security 959 846 costs for an electric generating facility.

Less amount included incurrent liabilities (142)- (29)

Unamortized loss on reacquireddebt - The unamortized

$ 817 $ 817 discount, premium and expense related to debt redeemed with a refinancing are deferred, amortized and recovered over ASSETS the life of the replacement issue.

Securitized regulatoryassets - The net book balance of the

Deferred environmentalcosts - The MPSC approved the Fermi 2 nuclear plant was written off in 1998 and an equivalent deferral and recovery of investigation and remediation costs regulatory asset was established. In 2001, the Fermi 2 regulatory associated with former manufactured gas plant sites.

asset and certain other regulatory assets were securitized pursuant to PA 142 and an MPSC order. A non-bypassable

Accrued GCR revenue - Receivable for the temporary securitization bond surcharge recovers the securitized under-recovery of and a return on gas costs incurred by regulatory asset over a fourteen-year period ending in 2015. MichCon which are recoverable through the GCR mechanism.

Recoverable income taxes related to securitized regulatory LIABILITIES assets - Receivable for the recovery of income taxes to be paid

Asset removal costs - The amount collected from customers for on the non-bypassable securitization bond surcharge. Anon- the funding of future asset removal activities.

bypassable securitization tax surcharge recovers the income tax

Excess securitizationsavings - Savings associated with the

Recoverable minimum pension liability-An additional 2001 securitization of Fermi 2 and other costs are refundable minimum pension liability was recorded under generally accepted to Detroit Edison's customers.

52 2004 annual report 11

Customer refund - 1997storm - I 'he over collection of 1997 customers ($240 million) and electric Customer Choice customers storm costs, which will be refundei I in accordance with the ($8 million). However, because of the rate caps under PA 141, not MPSC's November 2004 rate order. all of the increase was realized in 2004. The interim order also

Refundable income taxes - Incomeataxes refundable terminated certain transition credits and authorized transition to MichCon's customers representi ng the difference in charges to electric Customer Choice customers designed to result property-related deferred income taxes payable and amounts in $30 million in additional revenues. Additionally, the MPSC recognized pursuant to MPSC auth orization. authorized a reduced PSCR factor for all customers, designed to lower revenues by $126 million annually. However, the MIPSC order

Accrued GCR potential disallowar resulting from an MPSC order in Mliichone c Pontial s 2v00 rfnd GnRplan allowed subject toDetroit the capEdison in antoequal increase base ratesamount and offsetting for customers with thestill case that required MichCon to red, e e required reduction in the PSCR factor to maintain the total calculation of its 2002 GCR expens

e. capped rate levels currently in effect for these customers.

Accrued PSCR refund - Payable fo)rthe temporary The MPSC deferred addressing other items in the rate request, over-recovery of and a return on pa beginning with the MPSC's Novemi ber 2004 ber rate order, rte oder;rate 204 including a surcharge to recover regulatory assets, until a final order was issued.

transmission costs incurred by Det roit Edison which are recoverable through the PSCR me( chanism. MPSCFinalRate Order- On November 23, 2004, the MPSC issued an order for final rate relief. The MPSC determined that the base Electric Rate Case rate increase granted to Detroit Edison should be $336 million Rate Request - In June 2003, Detroit IEdison filed an application annually effective November 24, 2004 and is applicable to all with the MPSC requesting a change iii retail electric rates, customers not subject to the rate cap. The final order provides resumption of the PSCR mechanism,. md recovery of net stranded for the future recovery of losses resulting from electric Customer costs. The application and subsequent revisions resulted in a Choice. Additionally, beginning in 2005, the final order allows request to increase base rates by $583 Imillion annually. Detroit Edison to recover the discounts previously provided to In addition, Detroit Edison requested recovery of certain regulatory special manufacturing contract (SMC) customers of $38 million, assets. As subsequently discussed, Dc4troit Edison received interim resulting in an overall base rate increase of $374 million annually.

and final rate orders relating to its JAne 2003 rate application. As subsequently discussed, Detroit Edison has been deferring A summary of the rate orders follows 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 (inMillions) Increasell) Increased ) numerous issues relating to regulatory assets, including the Base Rate Revenue Deficiency $ 248 $ 336 amounts recoverable and the recovery mechanism. The final Recovery of SMC Discounts - 38 order authorized the recovery of a lower level of stranded costs Overall Base Rate Increase 248 374 than had been recorded through February 20, 2004, the date of PSCR Savings (126) (126) the interim order. Accordingly, Detroit Edison adjusted its net Total $ 122 $ 248 stranded costs related regulatory asset, which decreased 2004 net income by $21 million.

Actual Estimate -

(inMillions) 2004 2005 (2) Total The MPSC's final order authorizes the recovery of approximately Cumulative Recoverable RegulatoryAssets $385 million of regulatory assets through three mechanisms:

Clean Air Act $ 76 $ 68 $144

The first mechanism recovers certain accrued regulatory assets MISO Transmission Costs 27 49 76 over a five-year period using a regulatory asset recovery surcharge Excess Capital Expenditures 7 15 22 (RARS) and is collectible from all full service customers as their Customer Refund - 1997 Storm (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 Electric Choice Implementation Costs 95 6 101 balances. The recoverable regulatory assets include costs Net Stranded Costs 44 - 44 iassociated with Clean Air Act compliance, deferred Midwest Total S 247 $ 138 $385 Independent System Operator (MISO) transmission fees, and (1lThe impact of rate caps not included. deferred excess capital expenditures. The MPSC also authorized (2)Represents estimated amounts to be incur ,red in2005, as well as carrying the refunding of over collected 1997 storm costs.

costs on unrecovered balances, that were auithorized for recovery by the MPSC.

Actual amounts incurred are subject to revie Nin future MPSC proceedings, and

The second mechanism includes a surcharge to recover electric any overcollections or undercollections will 1bereflected infuture rates. Customer Choice implementation costs of $101 million and is MPSCInterim Rate Order- On Febi muary 20,2004, the MPSC collectible from both full service and electric Customer Choice issued an order for interim rate relie: f.The order authorized customers. This charge will not be implemented until all an interim increase in base rates, a t ransition charge for current rate caps expire in 2006 and will include carrying customers participating in the electr bin t Or -n LtIVIAZUVIIUI %JALIIU~b costs of 7%on unrecovered balances.

program and a new PSCR factor.

The third mechanism includes a surcharge to recover The interim base rate increase totale( d$248 million annually, $44 million in historical stranded costs incurred in 2002, effective February 21, 2004, and was a.pplicable to all customers not 2003 and January and February 2004 and is collectible from subject to a rate cap. The increase wa s allocated to both full-service 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 lowered, but residential rates would increase over a five-year final order period beginning in 2007. The MPSC anticipates that this

Rate increase was based on a 54% debt and 46% equity capital proceeding will be completed in time to have new rates in structure, and an 11% rate of return on common equity. effect no later than January 1,2006.

Customer rate caps do not expire until January 2006. As a Other Postemployment Benefits Costs Tracker result, the MPSC determined that there is a need to true-up On February 10, 2005, Detroit Edison filed an application requesting stranded costs for at least 2004. This true-up case must be filed MPSC approval of a proposed tracking mechanism for retiree health by March 31, 2005. The MPSC also permits Detroit Edison to file care costs. The application was filed as required pursuant to the additional annual stranded cost true-up proceedings if it deems MPSC's November 2004 order.

appropriate to do so pursuant to PA 141.

Electric Industry Restructuring

Transmission and MISO costs and costs associated with nitrogen oxide (NOx) allowances will be recoverable through the PSCR ElectricRates, Customer Choice and Stranded Costs - In 2000, mechanism and charged to full service customers; however, the Michigan Legislature enacted PA 141 that reduced electric costs associated with sulfur dioxide (SOx) allowances will not retail rates by 5%, as a result of savings derived from the issuance be included in the PSCR, but recoverable through base rates. of securitization bonds. The legislation also contained provisions freezing rates through 2003 and preventing rate increases

Full cost recovery of $550 million of Clean Air Act (i.e., rate caps) for small business customers through 2004 and environmental expenditures was authorized. We believe that for residential customers through 2005. The price freeze period future mandated environmental expenditures will also be expired on February 20, 2004 pursuant to an MPSC order.

recovered through base rates. In addition, PA 141 codified the MPSC's existing electric

Apension tracking mechanism was established to manage Customer Choice program and provided Detroit Edison with changes in pension costs. Under the tracking mechanism, the right to recover net stranded costs associated with Customer Detroit Edison would recover or refund pension costs above or Choice. Detroit Edison was also allowed to defer certain costs below the amount reflected in base rates. Detroit Edison was to be recovered once rates could be increased, including also required to propose a similar tracking mechanism for costs incurred as a result of changes in taxes, laws and other retiree health care costs. In February 2005, Detroit Edison governmental actions.

filed a request with the MPSC seeking authority to implement As required by PA 141, the MPSC conducted a proceeding to develop a tracking mechanism for retiree health care costs a methodology for calculating net stranded costs associated with (Other Postemployment Benefits Costs Tracker). electric Customer Choice. In a December 2001 order, the MPSC

Detroit Edison was ordered to file a rate unbundling and determined that Detroit Edison could recover net stranded costs restructuring case by March 23, 2005. As subsequently discussed, associated with the fixed cost component of its electric generation this rate restructuring proposal was ified on February 4,2005. operations. Specifically, there would be an annual proceeding

Changes to the existing electric Customer Choice program or true-up before the MPSC reconciling the receipt of revenues regarding customers returning to fall utility service. Customers associated with the fixed cost component of its generation services electing to participate in the electric Customer Choice program to the revenue requirement for the fixed cost component of will not be permitted to return to Detroit Edison's full service those services, inclusive of an allowance for the cost of capital.

rates for two years. Electric Customer Choice customers return- Any resulting shortfall in recovery, net of mitigation, would ing to full service must remain on bundled rates for at least one be considered a net stranded cost. The MPSC authorized year following their return. Customers who fail to give the Detroit Edison to establish a regulatory asset to defer recovery appropriate notice or do not stay on the electric Customer of its incurred stranded costs, subject to review in a subsequent Choice program for two years are required to pay the higher of annual net stranded cost proceeding.

the applicable tariff energy price plus 10%, or the market price In July 2003, the MPSC issued an order finding that Detroit Edison of power plus 10%, for any power taken from Detroit Edison. had no net stranded costs in 2000 and 2001. Detroit Edison filed In December 2004, Detroit Edison and other parties filed petitions a petition for rehearing of the July 2003 order, which the for rehearing relating to the MPSC's November 2004 final rate MPSC denied in December 2003. Detroit Edison has appealed.

order. Among other items, Detroit Edison's petition requests a As previously discussed, the MPSC's November 2004 final order correction of the capital structure used in determination of the authorized recovery of $44 million of historical stranded costs final order and recovery of certain disallowed costs. Detroit incurred in 2002, 2003 and January and February 2004 collectible Edison awaits an MPSC decision on the petitions for rehearing. from electric Customer Choice customers through transition charges. Since March 1,2004, Detroit Edison has recorded Electric Rate Restructuring Proposal $108 million of additional stranded costs as a regulatory asset On February 4, 2005, Detroit Edison filed a rate restructuring as the result of rate caps and higher electric Customer Choice proposal with the MPSC to restructure its electric rates and begin sales losses than included in the 2004 MPSC interim order.

phasing out subsidies that are part of its current pricing structure. Securitization- Detroit Edison formed The Detroit Edison The proposal would adjust rates for each customer class to be Securitization Funding LLC (Securitization LLC), a wholly owned reflective of the full costs incurred to service such customers. subsidiary, for the purpose of securitizing its qualified costs, Under the proposal, commercial and industrial rates would be primarily related to the unamortized investment in the Fermi 2 54 2004 annual report 11

nuclear power plant. In March 2001, the Securitization LLC costs, transmission expenses and NOx emission allowance costs.

issued $1.75 billion of securitization bonds, and Detroit Edison Detroit Edison self-implemented a factor of a negative 2.00 mills sold $1.75 billion of qualified costs to the Securitization LLC. per kWh on January 1, 2005. The Michigan Attorney General has The Securitization LLC is independent of Detroit Edison, as is its filed a motion for summary disposition of this proceeding based on ownership of the qualified costs. Due to principles of consolidation, arguments that the PSCR statute requires a fixed 48-month PSCR the qualified costs and securitization bonds appear on the factor. Woe cannot predict the nature or timing of actions the companys consolidated statement of financial position. MPSC will take on this motion.

The Company makes no claim to these assets. Ownership of Transmission Proceedings such assets has vested in the Securitization LLC and been assigned to the trustee for the securitization bonds. Neither On November 18, 2004, a FERC order approved a transmission the qualified costs nor funds from an MPSC approved non- pricing structure to facilitate seamless trading of electricity bypassable surcharge collected from Detroit Edison's customers between MISO and the PJM Interconnection. The pricing structure for the payment of costs related to the Securitization LLC and eliminates layers of transmission charges between the two regional securitization bonds are available to Detroit Edison's creditors. transmission organizations. The FERC noted that the new pricing structure may result in transmission owners facing abrupt revenue Excess SecuritizationSavings - In January 2004, the MPSC shifts. To facilitate the transition to the new pricing structure, the issued an order directing Detroit Edison to file a report by FERC authorized a Seams Elimination Cost Adjustment (SECA),

March 15, 2004, of the accounting of the savings due to effective from December 2004 through March 2006. Under MISO's securitization and the application of those savings through filing with the FERC, Detroit Edison's SECA obligation would be December 2003. In addition, Detroit Edison was requested to

$2.2 million per month from December 2004 through March 2005.

include in the report an estimate of the foregone carrying cost Detroit Edison has estimated that the SECA charge for the April associated with the excess securitization savings. Areport was 2005 through March 2006 period will be approximately $1million filed on February 16, 2004 in compliance with the MPSC order.

per month. On December 20, 2004, Detroit Edison'filed a request DTE2 Accounting Application for rehearing with the FERO which states, among other things, In 2003, we began the implementation of DTE2, a Company-wide that SECA is retroactive ratemaking and is unlawful under the initiative to improve existing processes and to implement new core Federal Power Act. Under the MPSC's November 2004 final rate information systems, including finance, human resources, supply order, transmission expenses are recoverable through the PSCR chain and work management. The new information systems are mechanism. Therefore, SECA charges, if ultimately imposed, replacing systems that are approaching the end of their useful should not have a financial impact to Detroit Edison.

lives. We expect the benefits of DTE2 to include lower costs, faster Gas Rate Case business cycles, repeatable and optimized processes, enhanced, Rate Request - In September 2003, MichCon filed an application internal controls, improvements in inventory management and with the MPSC for an increase in service and distribution charges reductions in system support costs.

(base rates) for its gas sales and transportation customers. The In July 2004, Detroit Edison filed an accounting application filing requests an overall increase in base rates of $194 million per with the MPSC requesting authority to capitalize and amortize year (approximately 7%increase, inclusive of gas costs), beginning DTE2 costs, consisting of computer equipment, software and January 1,2005. MichCon requested that the MPSC increase base development costs, as well as related training, maintenance and rates by $154 million per year on an interim basis by April 1,2004.

overhead costs. Through December 2004, we have expensed -

MPSCInterimRate Order - In September 2004, the MPSC issued approximately $20 million of training, maintenance and overhead an order granting interim rate relief to MichCon in the amount of costs pending MPSC action on our application. Detroit Edison is

$35 million. The interim rate order was based on a 50% debt and proposing a 15-year amortization period for the costs, exclusive 50% equity capital structure, and an 11.5% rate of return on common of the computer equipment costs.

equity. Amounts collected are subject to a potential refund pending Power Supply Cost Recovery Proceedings a final order in this rate case.

2004 Plan Year - An MPSC December 2003 order resumed the AMPSC StaffRecommendation on FinalRateRelief - The Staff PSCR mechanism that had been suspended while rates were has recominended a $76 million increase in base rates compared frozen. The order authorized a new PSCR factor for all customers to MichCon's requested base rate relief of $194 million. The Staff effective January 1,2004. The MPSC's February 2004 interim also supports a'provision, proposed by MichCon, that would allow order provided for a credit of 1.05 mills per kWh compared to a MichCon to recover or refund 90% of uncollectible accounts 2.04 mills per kWh charge previously in effect. Detroit Edison receivable expense above or below the amount that is reflected will file a 2004 PSCR reconciliation case by March 31, 2005. in base rates. In addition, the Staff proposed a 50% debt and 2005PlanYear - In September 2004, Detroit Edison filed its 50% equity capital structure utilizing a reduced rate of return 2005 PSCR plan case seeking approval of a levelized PSCR factor on common equity'of 11%. MichCon's current allowed rate of of 1.82 mills per kWh above the amount included in base rates. return on common equity is 11.5%.

In December 2004, Detroit Edison filed revisions to its 2005 PSCR MPSCProposalforDeciron(PFD)- The Administrative Law plan case in accordance with the November 2004 MPSC rate order. Judge (ALI) issued a PFD on MichCon's rate request on The revised filing seeks approval of a levelized PSCR factor of up December 10, 2004. The PFD recommends an increase in base to 0.48 mills per kWh above the new base rates established in the rates of $60 million. The PFD supports the Staff's recommendations final electric rate order. Included in the factor are power supply 2004 annual report 55

for capital structure, rate of return on common equity and for MichCon's 2003 GCR reconciliation case was filed with the the proposed reconciliation of uncollectible accounts receivable. MPSC in February 2004. In November 2004, the ALI issued a MichCon expects a final order in the first quarter of 2005. PFD in the 2003 reconciliation case. The AW recommended that MichCon recover the full $8 million related to the Enron issue Gas Industry Restructuring since MichCon had reason to believe at that time that cancellation In December 2001, the MPSC approved MichCon's application for of the contract was in the best interests of customers and since a voluntary, expanded permanent gas Customer Choice program, customers ultimately realized a benefit from the cancellation.

which replaced the experimental program that expired in March The AW agreed with the MPSC Staff that a $2 million accounting 2002. The number of customers eligible to participate in the gas adjustment related to exchange gas be disallowed.

Customer Choice program increased over a three-year period.

2004 Plan Year - In September 2003, MichCon filed its 2004 GCR Effective April 2004, all of MichCon's 1.2 million customers could plan case proposing a maximum GCR factor of $5.36 per Mcf.

elect to participate in the Customer Choice program, thereby MichCon agreed to switch from a calendar year to an operational purchasing their gas from suppliers other than MichCon.

year as a condition of its settlement in the 2003 GCR plan case.

The MPSC also approved the use of deferred accounting for The operational GCR year would run from April to March of the the recovery of implementation costs of the gas Customer Choice following year. To accomplish the switch, the 2004 GCR plan case program. As of December 2004, approximately 111,000 customers reflects a 15-month transitional period, January 2004 through are participating in the gas Customer Choice program.

March 2005. Under the transition proposal, MichCon would file Gas Cost Recovery Proceedings two reconciliations pertaining to the transition period; one address-2002 Plan Year - In December 2001, the MPSC issued an order ing the January 2004 to March 2004 period, the other addressing that permitted MichCon to implement GCR factors up to $3.62 per the remaining April 2004 to March 2005 period. The plan also thousand cubic feet (Mcf) for January 2002 billings and up to $4.38 proposes a quarterly GCR ceiling price adjustment mechanism.

per Mcf for the remainder of 2002. The order also allowed MichCon This mechanism allows MichCon to increase the maximum GCR to recognize a regulatory asset of approximately $14 million repre- factor to compensate for increases in market prices, thereby senting the difference between the $4.38 factor and the $3.62 factor reducing the possibility of a GCR under-recovery. Due to the for volumes that were unbilled at December 31, 2001. The regulatory sustained increase in market prices for natural gas, in June 2004 asset is subject to the 2002 GCR reconciliation process. In March the MPSC approved a temporary increase in the maximum GCR 2003, the MPSC issued an order in MichCon's 2002 GCR plan case. factor and a contingent factor which resulted in a new temporary The MPSC ordered MichCon to reduce its gas cost recovery expens- maximum factor of $6.62 per Mcf, effective from July 1,2004 es by $26.5 million for purposes of calculating the 2002 GCR factor until the MPSC issues its final order in this case. As of due to MichCon's decision to utilize storage gas during 2001 that December 31, 2004, MichCon has accrued a $55 million resulted in a gas inventory decrement for the 2001 calendar year. regulatory asset representing the under-recovery of actual gas costs incurred in 2004, and the 2003 and 2002 GCR under-recovery.

Although we recorded a $26.5 million reserve in 2003 to reflect the impact of this order, a final determination of actual 2002 2005-2006Plan Year - In December 2004, MichCon filed its revenue and expenses including any disallowances or adjustment, 2005-2006 GCR plan case proposing a maximum GCR factor will be decided in MichCon's 2002 GCR reconciliation case that was of $7.99 per Mcf. The plan includes a quarterly GCR ceiling filed with the MPSC in February 2003. The Staff and various inter- price adjustment mechanism. This mechanism allows MichCon vening parties in this proceeding are seeking to have the MPSC to increase the maximum GCR factor to compensate for disallow an additional $26 million, representing unbilled revenues increases in market prices, thereby reducing the possibility at December 2001. One party has also proposed the disallowance of a GCR under-recovery.

of half of an $8 million payment made to settle Enron bankruptcy Minimum Pension Liability issues. The other parties to the case have recommended that In December 2002, we recorded an additional minimum pension the Enron bankruptcy settlement be addressed in the 2003 GCR liability as required under SFAS No. 87, with offsetting amounts to reconciliation case. An MPSC Administrative Law Judge has an intangible asset and other comprehensive income. During 2003, recommended disallowances of $26.5 million related to the use the MPSC Staff provided an opinion that the MPSC's traditional rate of storage gas in 2001 and $26 million related to the December setting process allowed for the recovery of pension costs as measured 2001 unbilled issue, and recommended that the $8 million related by SFAS No. 87. Based on the MPSC Staff opinion, management to the Enron issue be addressed in the 2003 GCR reconciliation believes that it will be allowed to recover in rates the minimum case. We have included this item in our testimony in the 2003 GCR pension liability associated with its utility operations. In 2004 and reconciliation filed in February 2004. The Staff has recommended 2003, we reclassified approximately $605 million ($393 million net that MichCon be allowed to recover the entire $8 million related of tax) and $585 million ($380 million net of tax), respectively, of to the Enron issue. A final order in this proceeding is expected other comprehensive loss associated with the minimum pension in 2005. In addition, we filed an appeal of the March 2003 MPSC liability to a regulatory asset (Note 14).

order with the Michigan Court of Appeals. In November 2004, the Michigan Court of Appeals denied the appeal. Other 2003Plan Year - In July 2003, the MPSC approved an increase We are unable to predict the outcome of the regulatory matters in MichCon's 2003 GCR rate to a maximum of $5.75 per Mcf discussed herein. Resolution of these matters is dependent upon for the billing months of August 2003 through December 2003. 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 Decommissioning General The NRC has jurisdiction over the decommissioning of nuclear Fermi 2, our nuclear generating plant, began commercial power plants and requires decommissioning funding based upon operation in 1988. Fermi 2 has a design electrical rating (net) a formula. The MPSC and FERC regulate the recovery of costs of 1,150 megawatts. This plant represents approximately 10% of decommissioning nuclear power plants and both require the of Detroit Edison's summer net rated capability. The net book use of external trust funds to finance the decommissioning of balance of the Fermi 2 plant was written off at December 31, 1998, Fermi 2. Rates approved by the MPSC provide for the recovery and an equivalent regulatory asset was established. In 2001, the of decommissioning costs of Fermi 2. Detroit Edison is continuing Fermi 2 regulatory asset was securitized. See Note 4 - Regulatory to fund FERC jurisdictional amounts for decommissioning even Matters. Detroit Edison also owns Fermi 1,a nuclear plant that though explicit provisions are not included in FERC rates. We was shut down in 1972 and is currently being decommissioned. believe the MPSC and FERC collections will be adequate to fund The NRC has jurisdiction over the licensing and operation of the estimated cost of decommissioning using the NRC formula.

Fermi 2 and the decommissioning of Fermi 1. Detroit Edison has established a restricted external trust to hold funds collected from customers for decommissioning and the Property Insurance disposal of low-level radioactive waste. Detroit Edison collected Detroit Edison maintains several different types of property $38 million in 2004, $36 million in 2003 and $42 million in 2002 insurance policies specifically for the Fermi 2 plant. These policies from customers for decommissioning and low-level radioactive cover such items as replacement power and property damage. waste disposal. Net unrealized investment gains of $17 million The Nuclear Electric Insurance Limited (NEIL) is the primary and $62 million in 2004 and 2003, respectively, and $39 million supplier of these insurance polices. in losses in 2002, were recorded as adjustments to the nuclear Detroit Edison maintains a policy for extra expenses, including decommissioning trust funds and regulatory assets. At December replacement power costs necessitated by Fermi 2's unavailability due 31, 2004, investments in the external trust consisted of approxi-to an insured event. These policies have a 12-week waiting period and mately 55% in publicly traded equity securities, 43% in fixed provide an aggregate $490 million of coverage over a three-year period. debt instruments and 2%in cash equivalents.

Detroit Edison has $500 million in primary coverage and $2.25 billion At December 31, 2004 and 2003, Detroit Edison had external of excess coverage for stabilization, decontamination, debris removal, decommissioning trust funds of $546 million and $474 million, repair and/or replacement of property and decommissioning. The respectively, for the future decommissioning of Fermi 2. At combined coverage limit for total property damage is $2.75 billion. December 31, 2004 and 2003, Detroit Edison had an additional For multiple terrorism losses caused by acts of terrorism not covered $18 million and $22 million in trust funds for the decommissioning under the Terrorism Risk Insurance Act (MRIA) of 2002 occurring of Fermi 1. At December 31, 2004 and 2003, Detroit Edison also within one year after the first loss from terrorism, the NEIL policies had an external decommissioning trust fund for low-level radioac-would make available to all insured entities up to $3.2 billion, plus tive waste disposal costs of $26 million and $22 million, respectively.

any amounts recovered from reinsurance, government indemnity, or It is estimated that the cost of decommissioning Fermi 2, when other sources to cover losses. 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, Under the NEIL policies, Detroit Edison could be liable for maximum the company began the decommissioning of Fermi 1,with the assessments of up to approximately $28 million per event if the loss goal of removing the radioactive material and terminating the associated with any one event at any nuclear plant in the United Fermi 1 license. The decommissioning of Fermi 1 is expected States should exceed the accumulated funds available to NEIL. to be complete by 2009.

Public Liability Insurance As a result of adopting SFAS No. 143, Detroit Edison recorded a As required by federal law, Detroit Edison maintains $300 million retirement obligation liability for the decommissioning of Fermi 1 of public liability insurance for a nuclear incident. For liabilities and 2 and reversed previously recognized decommissioning liabili-arising from a terrorist act outside the scope of TRIA, the policy is ties. At December 31, 2004, we have recorded a liability for the subject to one industry aggregate limit of $300 million. Further, removal of the non-nuclear portion of the plants of $77 million.

under the Price-Anderson Amendments Act of 1988 (Act), deferred Nuclear Fuel Disposal Costs premium charges up to $101 million could be levied against each licensed nuclear facility, but not more than $10 million per year per In accordance with the Federal Nuclear Waste Policy Act of 1982, facility. Thus, deferred premium charges could be levied against all Detroit Edison has a contract with the U.S. Department of Energy owners of licensed nuclear facilities in the event of a nuclear inci- (DOE) for the future storage and disposal of spent nuclear fuel dent at any of these facilities. The Act expired on August 1, 2002. from Fermi 2. Detroit Edison is obligated to pay the DOE a fee of During 2003, the U.S. Congress extended the Act for commercial 1 mill per kNh of Fermi 2 electricity generated and sold. The fee nuclear facilities through December 31, 2003. However, provisions is a component of nuclear fuel expense. Delays have occurred in of the Act remain in effect for existing commercial reactors. the DOE's program for the acceptance and disposal of spent Legislation to extend the Act in conjunction with comprehensive nuclear fuel at a permanent repository. Until the DOE is able energy legislation is currently under debate in Congress. to fulfill its obligation under the contract, Detroit Edison is We cannot predict whether Congress will pass the legislation. 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 attributable to the partners instead of the partnerships. The accept spent nuclear fuel under the timetable set forth in the Act. minority interest allocation is therefore removed in computing income taxes associated with continuing operations.

NOTE-6 JOINTLY OWNED UTILITY PLANT Components of income tax expense (benefit) were as follows:

Detroit Edison has joint ownership interest in two power (Millions) 2004 2003 2002 plants, Belle River and Ludington Hydroelectric Pumped Continuing Operations Storage. Ownership information of the two utility plants Current federal and other as of December 31, 2004 was as follow s: income tax expense $ 31 $ 14 $ 135 Ludington Beile Hydroelectric Deferred federal income .. ( (29 River Pumped Storage tax expense (benefit) 134 < (1371 1219)

In-service date 1984-1985 1973 165- (123) (84)

Total plant capacity 1,026 MW 1,872 MW Discontinued operations - (4) 61 25 Ownership interest

49 % Cumulative Effect of Investment (inMillions) $ 1,581 $ 166 Accounting Changes - (15)

Accumulated depreciation (inMillions) $ 740 $ 88 Total $ 161 x$ (77) $ (59)

Detroit Edison's ownership interest is63% inUnit No. 1,81% of the facilities Internal Revenue Code Section 29 provides a tax credit for applicable to Belle River used jointly by the Belle River and St Clair Power Plants and 75% incommon facilities used at Unit No. 2 qualified fuels produced and sold by a taxpayer to an unrelated party during the taxable year. Our Section 29 tax ciedits earned Belle River but not utilized totaled $483 million and are carried forward The Michigan Public Power Agency (MPPA) has an ownership indefinitely as alternative minimum tax credits. The majority of interest in Belle River Unit No. 1 and other related facilities. our tax credit properties, including all of our synfuel projects, have The MPPA is entitled to 19% of the total capacity and energy received private letter rulings from the Internal Revenue Service of the plant and is responsible for the same percentage of the (IRS) that provide assurance as to the appropriateness of using plant's operation, maintenance and capital improvement costs. these credits to offset taxable income, however, these tax credits are subject to IRS audit and adjustment.

Ludington Hydroelectric Pumped Storage W'se have a net operating loss carryforward of $203 million that Consumers Energy Company has an ownership interest in the expires in years 2018 through 2020. 'We do not believe that a Ludington Hydroelectric Pumped Storage Plant. Consumers valuation allowance is required, as we expect to utilize the loss Energy is entitled to 51% of the total capacity and energy of the carryforward prior to its expiration.

plant and is responsible for the same percentage of the plant's Deferred tax assets and liabilities are recognized for the estimated operation, maintenance and capital improvement costs. future tax effect of temporary differences between the tax basis of assets or liabilities and the reported amounts in the financial NOTE-7 INCOMETAXES statements. Deferred tax assets and liabilities are classified as We file a consolidated federal income tax return. current or noncurrent according to the classification of the related assets or liabilities. Deferred tax assets and liabilities not related Total income tax expense (benefit) varied from the statutory to assets or liabilities are classified according to the expected federal income tax rate for the following reasons: reversal date of the temporary differences.

(Dollars inMillionsJ 2004 2003 2002 Deferred tax assets (liabilities) were comprised of the Effective federal income tax rate 21.1 % (34.4)% (16.7)% following at December 31:

Income before income taxes (Millions) 2004 2003 and minority interest - . 396 ' $ 266 $ 465 Property $ (1,193), i $(,1124)

Less minority interest _. (212). (91) (37) Securitized regulatory assets (778) (827)

Income from continuing $- 502 Alternative minimum tax operations before tax 6087 $ credit carryforward 483 497 Income tax expense at Merger basis differences 1251 132 35% statutory rate $ 213-; $ 125 $ 175 Pension and benefits (56)t (50)

Section 29tax credits (38) i (241) (250) Net operating loss 71'1 84 Investment tax credits ; (8) (8) (9) Other 317 380 Depreciation .:(4), (4) 2 $ (1,031) $ (908)

Employee Stock Ownership --" i Deferred income tax liabilities $ ((Z527'1 $(2,525)

Plan dividends (5) (5) (4) Deferred income tax assets 1,496 1 1,617 Other, net 7 10 2

$ (1,031) 1 $ (908)

Income tax expense (benefit) from continuing operations $ 165"! $ (123) $ (84) The IRS iscurrently conducting audits of our federal income tax The minority interest allocation reflects the adjustment to returns for the years 1998 through 2001. In additionl one of our earnings to allocate partnership losses to third party owners.

synfuel facilities isunder audit by the IRS for 2001. Audits of four The tax impact of partnership earnings and losses are 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 58 2004 annual report 1I

disagreements with governmental agencies about the tax treatment Options to purchase approximately one million shares of common of specific items. At December 31, 2004, the Company had accrued stock in 2004, five million shares in 2003 and one million shares in approximately $53 million for such uncertainties. We believe that 2002 were not included in the computation of diluted earnings our accrued tax liabilities are adequate for all years. 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 NOTE-8 COMMON STOCK AND associated with the equity-linked securities is not included in the EARNINGS PER SHARE computation of diluted earnings per share as these shares were Common Stock not dilutive (Note 9).

In March 2004, we issued 4,344,492 shares of DTE Energy common NOTE-9 LONG-TERM DEBT AND stock, valued at $170 million. The common stock was contributed PREFERRED SECURITIES to a defined benefit retirement plan.

Long-Term Debt Under the DTE Energy Company Long-Term Incentive Plan, we grant non-vested stock awards to key employees, primarily Our long-term debt outstanding and weighted average interest rates* of debt outstanding at December 31 was:

management. At the time of grant, we record the fair value of the non-vested awards as unearned compensation, which is reflected EinMillions) 2004 2003 as a reduction in common stock. The number of non-vested stock DTE Energy Debt, Unsecured ,,.

awards is included in the number of common shares outstanding; 6.1 %due 2006 to 2033 $ 1,945 l $ 2,005 however, for purposes of computing basic earnings per share, Detroit Edison Taxable Debt.

non-vested stock awards are excluded. Principally Secured 6.1 %due 2005 to 2032 1f672 1,485 Shareholders' Rights Agreement Detroit Edison Tax Exempt We have a Shareholders' Rights Agreement designed to maximize Revenue Bonds shareholder value should DTE Energy be acquired. Under certain 5.6% due 2008 to 2032 11,145 1,175 triggering events, each right entitles the holder to purchase from MichCon Taxable Debt, DTE Energy one one-hundredth of a share of Series AJunior Principally Secured Participating Preferred Stock of DTE Energy at a price of $90.00, 6.2% due 2006 to 2033 785: 772 subject to adjustment as provided for in the Shareholders' Rights Quarterly Income Debt Securities (QUIDS)

Agreement. The rights expire in October 2007. 7.5% due 2026 to 2038 ,385 385 Non-Recourse Debt A 56 78 Earnings per Share Other Long-Term Debt 95 106 We report both basic and diluted earnings per share. Basic ,4.6,0831 6,006 earnings per share is computed by dividing income from Less amount due within one year ' (410) (382) continuing operations by the weighted average'number of $S 5,673 $ 5,624 common shares outstanding during the period. Diluted earnings per share assumes the issuance of potentially dilutive common Securitization Bonds $ 1,496. $ 1,585 shares outstanding during the period and the repurchase of Less amount due within one year (96) (89) common shares that would have occurred with proceeds from 'S 1,400 - $ 1,496 the assumed issuance. Diluted earnings per share assume the Equity-Linked Securities -178 $ 185 exercise of stock options, vesting of non-vested stock awards, and the issuance of performance share awards. A reconciliation Trust Preferred - Linked Securities of both calculations is presented in the following table: 8.625% due 2038 $. , $ 103 7.8% due 2032 ' 186 186 (inMillions, except per share amounts) 2004 2003 2002 7.5% due 2044 103 Basic Earnings per Share - - -S2894 $ 289 Income from continuing operations 5, 442.6 $ 480.4 $ 585.7

Weighted average interest rates as of December31, 2004 Average number of common ';-- !

shares outstanding i§=.:-i172.6 167.7 164.0 We issued and optionally redeemed long-term debt Income per share of common consisting of the following:

stock based on average number 2005, of shares outstanding $ 2.561 $- 287 $3.57

Issued $400 million of Detroit Edison senior notes in two series, Diluted Earnings per Share $200 million of 4.8% series due 2015 and $200 million of 5.45%

Income from continuing operations i S -442.6 $ 480.4 S 585.7.- series due 2035. The proceeds were used to redeem the'$385 Average number of common million of 7.5% Quarterly Income Debt Securities due 2026 to 2028.

shares outstanding ' 172. 167.7, 164.0

Detroit Edison redeemed $76 million of 7.5% senior notes and Incremental shares from $100 million of 7.0% remarketed secured notes, which matured stock-based awards 7 .6 .8 February 2005.

Average number of dilutive - 2004 shares outstanding 1733 168.3 164.8

MCN Financing 11, an unconsolidated affiliate, redeemed Income per share of common -

$100 million of 8.625% Irust Originated Preferred Securities stock assuming issuance of due 2038. Accordingly, the underlying trust preferred-linked incremental shares $ 2.55 $ 2.85 $ 3.55 securities were also simultaneously redeemed.

2004 annual report 59

Redeemed $60 million of MCN Energy Enterprises Remarketable Securities 7.12% medium term notes. At December 31, 2004, $175 million of notes of Detroit Edison and

Issued $36 million of Detroit Edison 4-7/8% tax-exempt MfichCon were subject to periodic remarketings. The $100 million bonds due 2029, the proceeds of which were used to redeem scheduled to remarket in February 2005 was optionally redeemed

$36 million of Detroit Edison 6.55% tax-exempt bonds due 2024. by Detroit Edison, and no remarketings will take place in 2005.

Issued $32 million of Detroit Edison 4.65% tax-exempt bonds We direct the remarketing agents to remarket these securities due in 2028, the proceeds of which were used to redeem the at the lowest interest rate necessary to produce a par bid.

following Detroit Edison tax-exempt issues: $11.5 million of In the event that a remarketing fails, we would be required to 6.05% bonds due 2023, $7.5 million of 5.875% bonds due 2024, purchase the securities.

and $13 million of 6.45% bonds due 2024.

DTE Energy Trust II, an unconsolidated affiliate, issued an Quarterly Income Debt Securities (QUIDS) aggregate of $100 million of 7.50% Trust Originated Preferred Detroit Edison had three series of QUIDS outstanding at Securities. The proceeds from the issuance were loaned to December 31, 2004. Detroit Edison redeemed all of its DTE Energy in exchange for debt securities with essentially outstanding QUIDS on March 4, 2005.

the same terms as the related preferred securities. Equity-Linked Securities

Issued $250 million of DTE Energy floating rate notes due in In June 2002, DTE Energy issued 6.9 million equity security 2007. The floating rate is based on 3 month LIBOR plus 0.95%.

units with gross proceeds from the issuance of $172.5 million.

These notes may be called at par in June 2005. The proceeds were used to repay short-term borrowings incurred in connec- An equity security unit consists of a stock purchase contract and tion with the June 2004 redemption of $250 million DTE Energy a senior note of DTE Energy. Under the stock purchase contracts, 6.0% senior notes. we will sell, and equity security unit holders must buy, shares of DTE Energy common stock in August 2005 for $172.5 million.

Issued $200 million of Detroit Edison 5.40% senior notes due in The issue price per share and the exact number of common shares 2014. The proceeds were used to repay short-term borrowings to be sold is dependent on the market value of a share in August and for general corporate purposes.

2005. The issue price will be not less than $43.25 or more than

Issued $120 million of MichCon 5.0% senior notes due in 2019. $51.90 per common share, with the corresponding number of The proceeds were used to redeem the following two issues: shares issued of not more than 4.0 million or less than 3.3 million

$52 million of 6.85% senior notes due 2038 and $55 million of shares. We are also obligated to pay the security unit holders 6.85% senior notes due 2039.

a quarterly contract adjustment payment at an annual rate of 2003 4.15% of the stated amount until the purchase contract settlement

Issued $400 million of DTE Energy 6-3/8% senior notes date. We recorded the present value of the contract adjustment maturing in April 2033. In conjunction with this issuance, payments of $26 million in long-term debt with an offsetting DTE Energy exchanged $100 million principal amount of reduction in shareholders' equity. The liability is reduced as existing DTE Enterprises, Inc. debt due April 2008. The the contract adjustment payments are made.

exchange premium and other costs associated with the original Each senior note has a stated value of $25, pays an annual interest debt were deferred and are being amortized to interest expense rate of 4.60% and matures in August 2007. The senior notes are over the term of the new debt.

pledged as collateral to secure the security unit holders' obligation

Redeemed $100 million of DTE Energy 6.17% Remarketed to purchase DTE Energy common stock under the stock purchase Notes maturing in 2038. contracts. The security unit holders may satisfy their obligations

Issued $49 million of Detroit Edison 5.5% tax exempt bonds under the stock purchase contracts by allowing the senior notes maturing in 2030. to be remarketed with proceeds being paid to DTE Energy as

Redeemed $49 million of Detroit Edison 6.55% tax-exempt consideration for the purchase of stock under the stock purchase bonds maturing in 2024. contracts. Alternatively, holders may choose to continue holding

Issued $200 million of MichCon 5.7% senior notes the senior notes and use cash as consideration for the purchase maturing in March 2033. of stock under the stock purchase contracts.

Redeemed $314 million of Detroit Edison taxable debt with an Net proceeds from the equity security unit issuance totaled average interest rate of 7.4% and maturities from 2003-2023. $167 million. Expenses incurred in connection with this issuance

Redeemed $34 million of Detroit Edison 6.875% tax-exempt totaled $5.6 million and were allocated betwveen the senior notes bonds maturing in 2022. and the stock purchase contracts. The amount allocated to the In the years 2005 - 2009, our long-term debt maturities are senior notes was deferred and will be recognized as interest

$507 million, $680 million, $597 million, $455 million and expense over the term of the notes. The amount allocated to

$361 million, respectively. 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 facility from $137.5 million to $68.75 million. MichCon entered preferred securities. Payments we make are used by the trusts to into a $243.75 million, five-year facility and lowered its three-year make cash distributions on the preferred securities it has issued. facility from $162.5 million to $81.25 million. The five-year facili-We have the right to extend interest payment periods on the debt ties replace the October 2003 364-day facilities, which expired.

securities. Should we exercise this right, we cannot declare or pay The three-year revolving credit facilities expire in October 2006.

dividends on, or redeem, purchase or acquire, any of our capital The five- and three-year credit facilities are with a syndicate of stock during the deferral period. banks and may be utilized for general corporate borrowings, but primarily are intended to provide liquidity support for each of the DTE Energy has issued certain guarantees with respect to Companies' commercial paper programs. Borrowings under the payments on the preferred securities. These guarantees, when facilities will be available at prevailing short-term interest rates.

taken together with our obligations under the debt securities The agreements require each of the Companies to maintain a and related indenture, provide full and unconditional guarantees debt to total capitalization ratio of no more than .65 to I and an of the trusts' obligations under the preferred securities.

EBITDA to interest ratio of no less than 2 to 1.The Companies are Financing costs for these issuances were paid for and deferred by currently in compliance with these financial covenants. Should DTE Energy. These costs are being amortized using the straight-line either Detroit Edison or MichCon have delinquent debt obligations method over the estimated lives of the related securities. of at least $25 million to any creditor, such delinquency will be Cross Default Provisions considered a default under DTE Energy's credit agreements.

Substantially all of the net utility properties of Detroit Edison As of December 31, 2004, we had outstanding commercial paper and MichCon are subject to the lien of mortgages. Should of $402 million and other short-term borrowings of $1million.

Detroit Edison or MichCon fail to timely pay their indebtedness Detroit Edison also has a $200 million short-term financing agree-under these mortgages, such failure will create cross defaults in ment secured by customer accounts receivable. This agreement the indebtedness of DTE Energy Corporate. contains certain covenants related to the delinquency of accounts receivable. Detroit Edison is currently in compliance with these Preferred and Preference covenants. W\e had no balances outstanding under this financing Securities - Authorized and Unissued agreement at December 31, 2004.

At December 31, 2004, DTE Energy had 5 million shares of The weighted average interest rates for short-term borrowings preferred stock without par value authorized, with no shares issued. Of such amount, 1.5 million shares are reserved for were 2.4% and 1.9% at December 31, 2004 and 2003, respectively.

issuance in accordance with the Shareholders' Rights Agreement.

NOTE-11 CAPITAL AND OPERATING LEASES At December 31, 2004, Detroit Edison had approximately 6.75 million shares of preferred stock with a par value of Lessee - We lease various assets under capital and operating leases, including coal cars, a gas storage field, office buildings, a

$100 per share and 30 million shares of preference stock with a warehouse, computers, vehicles and other equipment. The lease par value of $1per share authorized, with no shares issued.

arrangements expire at various dates through 2029. Portions of At December 31, 2004, MichCon had 7 million shares of preferred the office buildings are subleased to tenants.

stock with a par value of $1per share and 4 million shares of Future minimum lease payments under non-cancelable leases at preference stock with a par value of $1per share authorized, December 31, 2004 were:

with no shares issued.

Capital Operating (inMlions) Leases Leases NOTE-10 SHORT-TERM CREDIT 2005 $ 11 $ 64 ARRANGEMENTS AND BORROWINGS 2006 13 56 In May 2004, DTE Energy entered into a $375 million two-year 2007 10 47 unsecured revolving credit facility with a group of banks to be 2008 11 40 utilized for general corporate borrowings. DTE Energy had 2009 11 38 approximately $148 million of letters of credit outstanding Thereafter 38 378 against this facility at December 31, 2004. This agreement Total minimum lease payments 94 S 623 requires the company to maintain a debt to total capitalization Less imiputed interest (211 ratio of no more than .65 to I and an "earnings before interest, Present value of net minimum lease payments 73 taxes, depreciation and amortization" (EBITDA) to interest Less current portion (7) ratio of no less than 2 to 1.DTE Energy is currently in Non-current portion $ 66 compliance with these financial covenants.

In October 2004, DTE Energy entered into a $525 million, Total minimum lease payments for operating leases have not been five-year unsecured revolving credit facility and lowered its reduced by future minimum sublease rentals totaling $6million existing three-year revolving credit facility from $350 million under non-cancelable subleases expiring at various dates to 2020.

to $175 million. Detroit Edison and MichCon also entered into Rental expense for operating leases was $75 million in 2004, similar revolving credit facilities. Detroit Edison entered into a $73 million in 2003 and $40 million in 2002.

$206.25 million, five-year facility and lowered its three-year 2004 annual report 61

Lessor - MichCon leases a portion of its pipeline system to the Commodity Price Risk Vector Pipeline Partnership through a capital lease contract that Utility Operations expires in 2020, with renewal options extending for five years.

The components of the net investment in the capital lease at DetroitEdison - Detroit Edison generates, purchases, distributes December 31, 2004, were as follows: and sells electricity. Detroit Edison uses forward energy, capacity, (inMillions) and futures contracts to manage changes in the price of electricity 2005 $ 9 and fuel. These derivatives are designated as cash flow hedges 2006 9 or meet the normal purchases and sales exemption and are 2007 9 therefore accounted for under the accrual method. There were 2008 9 no commodity price risk cash flow hedges for utility operations 2009 9 at December 31, 2004.

Thereafter 98 ffichCon - MichCon purchases, stores, transmits and distributes Total minimum future lease receipts 143 and sells natural gas. MichCon has fixed-priced contracts for Residual value of leased pipeline 40 portions of its expected gas supply requirements through 2005.

Less unearned income (101) These contracts are designated and qualify for the normal Net investment incapital lease 82 purchases and sales exemption and are therefore accounted Less current portion (1) for under the accrual method. i

$ 81 Commodity price risk associated with our utilities is limited due to the PSCR and GCR mechanisms (Note 1).

NOTE-12 FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS Non-Utility Operations We comply with SFAS No. 133, "AccountingforDerivative EnergyMarketing & rading - Energy Marketing and Trading Instruments and HedgingActivities," as amended by markets and trades wholesale electricity and natural gas physical SFAS No. 138 and SFAS No. 149. Listed below are important products, trades financial instruments, and provides risk manage-SFAS No. 133 requirements: ment services utilizing energy commodity derivative instruments.

All derivative instruments must be recognized as assets or Forwards, futures, options and swap agreements are used to liabilities and measured at fair value, unless they meet the manage exposure to the risk of market price and volume fluctua-normal purchases and sales exemption. tions on its operations. These derivatives are accounted for by recording changes in fair value to earnings, usually is adjustments

The accounting for changes in fair value depends upon the to operating revenues or fuel, purchased power and gas expense.

purpose of the derivative instrument and whether it is This fair value accounting better aligns financial reporting with designated as a hedge and qualifies for hedge accounting.

the way the business is managed and its performance measured.

Special accounting is allowed for a derivative instrument quali-Energy Marketing & Trading experiences earnings volatility as a fying as a hedge and designated as a hedge for the variability of cash flow associated with a forecasted transaction. Gain or loss result of its gas inventory and other non-derivative assets that do associated with the effective portion of the hedge is recorded in not qualify for fair value accounting under U.S.generally accepted other comprehensive income. The ineffective portion is recorded accounting principles. Although the risks associated with these to earnings. Amounts recorded in other comprehensive income asset positions are substantially offset, requirements to fair value will be reclassified to net income when the forecasted transac- the underlying derivatives result in unrealized gains and losses tion affects earnings. If a cash flow hedge is discontinued being recorded to earnings that eventually reverse upon settlement.

because it is likely the forecasted transaction will not occur, Energy Services and Biomass - Our Energy Services and Biomass net gains or losses are immediately recorded to earnings. businesses generate Section 29 tax credits. Additionally, through

Special accounting is also allowed for a derivative instrument December 2004, Energy Services has sold majority interests in qualifying as a hedge and designated as a hedge of the changes eight of its nine synthetic fuel production plants. Proceeds from in fair value of an existing asset, liability or firm commitment. the sales are contingent upon production levels, the production Gain or loss on the hedging instrument is recorded into earnings. qualifying for Section 29 tax credits, and the value of such credits.

An offsetting loss or gain on the underlying asset, liability or firm Section 29 tax credits are subject to phase out if domestic crude commitment is also recorded to earnings. oil prices reach certain levels. See Note 13 for further discussion.

Our primary market risk exposure is associated with commodity To manage our exposure in 2005 to the risk of an increase in oil prices, credit, interest rates and foreign currency. Wre have prices that could reduce synfuel sales proceeds, we entered into risk management policies to monitor and decrease market risks. a series of derivative contracts covering a specified number of We use derivative instruments to manage some of the exposure. barrels of oil. The derivatives, coupled with other contracts, Except for the activities of the Energy Marketing &Trading economically hedge approximately 65% of our 2005 synfuel segment, we do not hold or issue derivative instruments for cash flow exposure. The derivative contracts involve purchased trading purposes. The fair value of all derivatives is shown as and written call options that provide for net cash settlement "assets or liabilities from risk management and trading activities" at expiration based on the full year 2005 average New York in the consolidated statement of financial position. 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 long-term debt securities. The carrying value of certain other of oil exceeds approximately $56 per barrel, the derivatives will financial instruments, such as notes payable, customer deposits yield a payment equal to the excess of the average NYMEX price and notes receivable approximate fair value and are not shown.

over $56 per barrel, multiplied by the number of barrels covered, 2004 2003 up to a maximum price of approximately $68 per barrel. The - FairValue S Carrying Value i FairValue Canyig Value agreements do not qualify for hedge accounting and, as a result, Long-Term Debt i8.5 billion - $ Obillion l S8.5 billion $ 7.9 billion changes in the fair value of the options are recorded currently in earnings. The fair value changes are recorded as adjustments to NOTE-13 COMMITMENTS AND the gain from selling interests in synfuel facilities and therefore CONTINGENCIES included in the "Asset gains and losses, net" line item in the con- Synthetic Fuel Operations solidated statement of operations.

We partially or wholly own nine synthetic fuel production facilities.

Gas Production - Our Gas Production business is engaged in natu- Synfuel facilities chemically change coal, including waste and ral gas exploration, development and production. We use deriva- marginal coal, into a synthetic fuel as determined under applica-tive contracts to manage changes in the price of natural gas. These ble IRS rules. Section 29 of the Internal Revenue Code provides derivatives are designated as cash flow hedges. Amounts recorded tax credits for the production and sale of solid synthetic fuels in other comprehensive loss will be reclassified to earnings as the produced from coal. To qualify for the Section 29 tax credits, the related forecasted production affects earnings through 2013. In synthetic fuel must meet three primary conditions: (1) there must 2005, we estimate reclassifying $35 million of losses to earnings. be a significant chemical change in the coal feedstock, (2) the Credit Risk product must be sold to an unaffiliated entity, and (3) the produc-tion facility must have been placed in service before July 1,1998.

Our utility and non-utility businesses are exposed to credit In addition to meeting the qualifying conditions, a taxpayer must risk if customers or counterparties do not comply with their have sufficient taxable income to earn the Section 29 tax credits.

contractual obligations. We maintain credit policies that significantly minimize overall credit risk. These policies include In-Servnce Date- During July 2004, several unaffiliated companies an evaluation of potential customers' and counterparties' financial announced that they have been notified that the IRS intends to condition, credit rating, collateral requirements or other credit challenge the placed in service dates for some of their synfuel enhancements such as letters of credit or guarantees. We use facilities. If the IRS ultimately prevails, Section 29 credits claimed standardized agreements that allow the netting of positive and by these companies would be disallowed. The placed in-service negative transactions associated with a single counterparty issue is fact-driven and specific to each facility. The in-service dates for eight of our nine synfuel plants have been favorably Interest Rate Risk reviewed by the IRS in cornunction with issuing determination W'se use interest rate swaps, treasury locks and other derivatives letters and/or recently completed audits. We believe all nine of to hedge the risk associated with interest rate market volatility. our synthetic fuel plants meet the required in-service condition.

In 2004 and 2000, we entered into a series of interest rate Through December 31, 2004, we have generated and recorded derivatives to limit our sensitivity to market interest rate risk approximately $512 million in synfuel tax credits.

associated with the issuance of long-term debt. Such instruments Oil Pices - To reduce U.S. dependence on imported oil, the were designated as cash flow hedges. We subsequently issued Internal Revenue Code provides Section 29 tax credits as an long-term debt and terminated these hedges at a cost that is incentive for taxpayers to produce fuels from alternative sources.

included in other comprehensive loss. Amounts recorded in This incentive is not deemed necessary if the price of oil increases other comprehensive loss will be reclassified to interest expense and provides a natural market for these fuels. As such, the tax as the related interest affects earnings through 2030. In 2005, credit in a given year is reduced if the Reference Price of oil we estimate reclassifying $6million of losses to earnings. within that year exceeds a threshold price. The Reference Price Foreign Currency Risk of a barrel of oil is an estimate of the annual average wellhead Energy Marketing and Trading has foreign currency forward price per barrel for'domestic crude oil, which in recent years contracts to hedge fixed Canadian dollar commitments existing has been $3- $4lower than the NYMEX price for light, sweet under power purchase and sale contracts and gas transportation, crude oil. The threshold price at which the credit begins to be contracts. We entered into these contracts to mitigate any price reduced was set in 1980 and is adjusted annually for inflation.

volatility with respect to fluctuations of the Canadian dollar relative For 2004, we estimate that the threshold price at which the tax to the U.S. dollar. Certain of these contracts are designated as cash credit would have begun to be reduced was $51.34 and would -

flow hedges with changes in fair value recorded to other compre- have been completely phased out if the Reference Price reached hensive income. Amounts recorded to other comprehensive inc6me $64.45. The Reference Price of oil is estimated to be $37.61 for are classified to operating revenues or fuel, purchased power and 2004. We also estimate that the 2005 average wellhead price gas expense when the related hedged item affects earnings. per barrel of oil would have to exceed approximately $52.37 per barrel to begin phase out and exceed approximately $65.74 per Fair Value of Other Financial Instruments barrel to eliminate the credits. We cannot predict with any The fair value of financial instruments is determined by using accuracy the future price of a barrel of oil.

various market data and other valuation techniques. The table Numerous recent events have increased domestic crude oil below shows the fair value relative to the carrying value for prices, including terrorism, storm-related supply disruptions 2004 annual report 63

and worldwide demand. If the credit is reduced or eliminated reserve. Enterprises employed outside consultants to evaluate in future years, our financial statements would be negatively remediation alternatives for these sites, to assist in estimating its impacted. Al'e continue to evaluate the current volatility in oil potential liabilities and to review its archived insurance policies.

prices and alternatives available to mitigate our exposure to oil As a result of these studies, Enterprises accrued an additional prices as part of our synfuel-related risk management strategy. liability and a corresponding regulatory asset of $35 million during To manage our exposure to oil prices in 2005, we entered into 1995. In early December 2004, Enterprises retained multiple oil-related derivative contracts. See Note 12 for further discussion. environmental consultants to estimate the projected cost to remediate each MGP facility. The results of the evaluation Environmental indicated that the MGP reserve should be set at $24 million.

Air- The EPA issued ozone transport and acid rain regulations During 2004, Enterprises spent approximately $2 million investigat-and, in December 2003, proposed additional emission regulations ing and remediating these former MGP sites. At December 31, relating to ozone, fine particulate and mercury air pollution.

2004, the reserve balance was $24 million of which $4.5 million The new rules have led to additional controls on fossil-fueled was classified as current. Any significant change in assumptions, power plants to reduce nitrogen oxide, sulfur dioxide, carbon diox-such as remediation techniques, nature and extent of contamina-ide and particulate emissions. To comply with these new controls, tion and regulatory requirements, could impact the estimate of Detroit Edison has spent approximately $580 million through remedial action costs for the sites and, therefore, have an effect December 2004, and estimates that it will spend up to $100 million on the Company's financial position and cash flows. However, in 2005 and incur from $700 million to $1.3 billion of additional we anticipate the cost deferral and rate recovery mechanism future capital expenditures over the next five to eight years to approved by the MPSC will prevent environmental costs from satisfy both the existing and proposed new control requirements.

having a material adverse impact on our results of operations.

Under the June 2000 Michigan restructuring legislation, beginning January 1, 2004, annual return of and on this capital expenditure, Detroit Edison conducted remedial investigations at contaminated in excess of current depreciation levels, could be deferred in sites, including two former MGP sites, the area surrounding an ash ratemaking, until after the expiration of the rate cap period, landfill and several underground and aboveground storage tank presently expected to end on December 31, 2005 upon AIPSC locations. The findings of these investigations indicated that the authorization. Under PA 141 and the MPSC's November 2004 final cost to remediate these sites is approximately $8 million, which rate order, we believe that prudently incurred capital expenditures, is expected to be incurred over the next several years. As a result in excess of current depreciation levels, are recoverable in rates. of the investigation, Detroit Edison accrued an $8 million liability during 2004.

flater- Detroit Edison is required to examine alternatives for reducing the environmental impacts of the cooling water Guarantees intake structures at several of its facilities. Based on the results In certain circumstances we enter into contractual guarantees.

of the studies to be conducted over the next several years, We may guarantee another entity's obligation in the event it fails Detroit Edison may be required to install additional control to perform. We may provide guarantees in certain indemnification technologies to reduce the impacts of the intakes. It is estimated agreements. Finally, we may provide indirect guarantees of the that eve will incur up to $50 million over the next five to seven indebtedness of others. Below are the details of specific material years in additional capital expenditures for Detroit Edison. guarantees we currently provide. Our other guarantees are not ContaminatedSites - Prior to the construction of major interstate individually material and total approximately $40 million at natural gas pipelines, gas for heating and other uses was manufac- December 31, 2004.

tured locally from processes involving coal, coke or oil. Enterprises Sale of Interests in Synfuel Facilities (MichCon and Citizens) owns, or previously owned, 18 such former We have provided certain guarantees and indemnities in manufactured gas plant (MGP) sites. During the mid-1980's, conjunction with the sales of interests in our synfuel facilities.

Enterprises conducted preliminary environmental investigations at The guarantees cover general commercial, environmental and former MGP sites, and some contamination related to the tax-related exposure and will survive until 90 days after by-products of gas manufacturing was discovered at each site.

expiration of all applicable statute of limitations, or indefinitely, The existence of these sites and the results of the environmental depending on the nature of the guarantee. We estimate that investigations have been reported to the MDEQ.

our maximum liability under these guarantees at Enterprises is remediating eight of the former MGP sites and December 31, 2004 totals $905 million.

conducting more extensive investigations at five other former MGP sites. Enterprises received MDEQ closure of one site, Parent Company Guarantee of and a determination that it is not a responsible party for Subsidiary Obligations three other sites. Enterprises received closure from the We have issued guarantees for the benefit of various non-utility EPA in 2002 for one site. subsidiary transactions. In the event that DTE Energy's credit In 1984, Enterprises established a $12 million reserve for costs rating is downgraded below investment grade, certain of these associated with enviromnental investigation and remediation guarantees would require us to post cash or letters of credit activities. During 1993, MichCon received MPSC approval of a valued at approximately $356 million at December 31, 2004.

cost deferral and rate recovery mechanism for investigation and This estimated amount fluctuates based upon the provisions remediation costs incurred at former MGP sites in excess of this and maturities of the underlying agreements.

64 2004 annual report 11

Personal Property Taxes 2008 and recorded an additional liability of $20 million for Prior to 1999, Detroit Edison, MichCon and other Michigan future commitments. Also, we have guaranteed bank loans that utilities asserted that Michigan's valuation tables result in the Thermal Ventures II, LP may use for capital improvements to substantial overvaluation of utility personal property. Valuation the steam heating system.

tables established by the Michigan State Tax Commission (STC) In 2004, we modified our future purchase commitments under a are used to determine the taxable value of personal property transportation agreement with an interstate pipeline company and based on the property's age. In November 1999, the STC approved terminated a related long-term gas exchange (storage) agreement.

new valuation tables that more accurately recognize the value of Under the gas exchange agreement, we received gas from the a utility's personal property. The new tables became effective in customer during the summer injection period and redelivered 2000 and are currently used to calculate property tax expense. the gas during the winter heating season. The agreements were However, several local taxing jurisdictions have taken legal at rates that were not reflective of current market conditions action attempting to prevent the STC from implementing the and had been fair valued under accounting principles generally new valuation tables and have continued to prepare assessments accepted in the U.S. In 2002, the fair value of the transportation based on the superseded tables. The legal actions regarding the agreement was frozen when it no longer met the definition of a appropriateness of the new tables were before the Michigan Tax derivative as a result of FERC Order 637. The fair value amounts Tribunal (MIT) which, in April 2002, issued its decision essentially were being amortized to income over the life of the related affirming the validity of the STC's new tables. In June 2002, agreements, representing a net liability of approximately petitioners in the case filed an appeal of the MITs decision with $75 million as of December 31, 2003. As a result of the contract the Michigan Court of Appeals. In January 2004, the Michigan modification and termination, we recorded an adjustment to the Court of Appeals upheld the validity of the new tables. With no net liability increasing 2004 earnings by $48 million, net of taxes.

further appeal by the petitioners available, the MTT began to At December 31, 2004, we have entered into numerous long-term schedule utility personal property valuation cases for Prehearing purchase commitments relating to a variety of goods and services General Calls. Detroit Edison and MichCon have filed motions required for our business. These agreements primarily consist and the AMT agreed to place their cases in abeyance pending of fuel supply commitments and energy trading contracts.

the conclusion of settlement negotiations being conducted by We estimate that these commitments will be approximately State of Michigan Treasury officials. On February 14, 2005, $7.3 billion through 2027. We also estimate that 2005 base level MIT issued a scheduling order that lifts the prior abeyances capital expenditures will be $1.1 billion. We have made certain in a significant number of Detroit Edison and MichCon appeals. commitments in connection with expected capital expenditures.

The scheduling order sets litigation calendars for these cases extending into mid-2006. Bankruptcies Detroit Edison and MichCon continue to record property We purchase and sell electricity, gas, coal and coke from and to tax expense based on the new tables. Detroit Edison and numerous companies operating in the steel, automotive, energy MichCon will continue through settlement or litigation to and retail industries. Several customers have filed for bankruptcy seek to apply the new tables retroactively and to ultimately protection under Chapter 11 of the U.S. Bankruptcy Code. We have resolve the pending tax appeals related to 1997 through 1999. negotiated or are currently involved in negotiations with each of This is a solution supported by the STC in the past. To the the companies, or their successor companies, that have filed for extent that settlements cannot be achieved with the jurisdic- bankruptcy protection. We regularly review contingent matters tions, litigation regarding the valuation of utility property will relating to purchase and sale contracts and record provisions for delay any recoveries by Detroit Edison and MichCon. amounts considered probable of loss. We believe our previously accrued amounts are adequate for probable losses. The final Other Commitments resolution of these matters is not expected to have a material Detroit Edison has an Energy Purchase Agreement to purchase effect on our financial statements in the period they are resolved.

steam and electricity from the Greater Detroit Resource Recovery Other Authority (GDRRA). Under the Agreement, Detroit Edison will purchase steam through 2008 and electricity through June 2024. Ue are involved in certain legal, regulatory, administrative In 1996, a special charge to income was recorded that included a and environmental proceedings before various courts, reserve for steam purchase commitments in excess of replacement arbitration panels and governmental agencies concerning costs from 1997 through 2008. The reserve for steam purchase claims arising in the ordinary course of business. These commitments is being amortized to fuel, purchased power and gas proceedings include certain contract disputes, environmental expense with non-cash accretion expense being recorded thr6ugh reviews and investigations, audits, inquiries from various 2008. We purchased $42 million of steam and electricity in 2004, regulators, and pending judicial matters. We cannot predict

$39 million in 2003 and $37 million in 2002. We estimate steam the final disposition of such proceedings. We regularly review and electric purchase commitments through 2024 will not exceed legal matters and record provisions for claims that are

$472 million. As discussed in Note 3- Dispositions, in January considered probable of loss. The resolution of pending 2003, we sold the steam heating business of Detroit Edison to proceedings is not expected to have a material effect on our Thermal Ventures II, LP. Due to terms of the sale, Detroit Edison operations or financial statements in the period they are resolved.

remains contractually obligated to buy steam from GDRRA until 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 Qualified Nonqualified Pension Plans Pension Plans TRUSTEED ASSETS (inMillions) 2004 2003 2004 2003 Measurement Date Measurement Date Nov.30 Dec. 31 Nov.30. Dec. 31 In the fourth quarter of 2004, we changed the date for actuarial Accumulated Benefit measurement of our obligations for benefit programs from Obligation-End of Period $ 2.689 S 2,556 $ 54 - $ 57 December 31 to November 30. We believe the one-month change Projected Benefit 3 of the measurement date is a preferable change as it allows time Obligation-Beginning of Period $ Z745 $ Z499 $ 59-x l $ 50 for management to plan and execute its review of the completeness ServiceCost .58 48 2,, 2 and accuracy of its benefit programs results and to fMlly reflect the Interest Cost 168 164 3 4 impact on its financial results. The change did not have a material Actuarial Loss (Gain) 76 201 (4)' 6 effect on retained earnings as of January 1, 2004, and income from Benefits Paid 7 (149) 1159) (4)V (3) continuing operations, net income and related per share amounts Plan Amendments 1 (8) - _

for any interim period in 2004. Accordingly, all amounts reported in Projected Benefit Obligation-End of Period $ Z899 $ 2,745 ; $ 56X. $ 59 the following tables for balances as of December 31, 2004 are based on a measurement date of November 30, 2004. Amounts reported in Plan Assets at Fair Value-Beginning of Period $ 2,348 $ 1,845 i - $ -

tables for the year ended December 31, 2004 and for balances as of Actual Retum on PlanAssets .- .196 440' December 31,2003 are based on a measurement date of December Company Contributions - 170 222 4 3 31, 2003. Amounts reported in tables for the year ended December Benefits Paid (149) (159) (4) (31 1-31, 2003 are based on a measurement date of December 31,2002. Plan Assets at Fair Value-End of Period $2,565 $ 2,348 ' $ -

s$

Qualified and Nonqualified Pension Plan Benefits Funded Status of the Plans $ (334) $ (397) $(56J. $ (59)

We have defined benefit retirement plans for eligible represented Unrecognized and nonrepresented employees. The plans are noncontributory, Netloss 1,043 1,010 15. 18 cover substantially all employees and provide retirement benefits Priorservice cost 34 41 1 3 based on the employees' years of benefit service, average final Net Amount Recognized at compensation and age at retirement. Certain represented and Measurement Date 743 654 (40)K6 (381 nonrepresented employees are covered under cash balance Company Contribution in December 2004 - - 1. -

benefits based on annual employer contributions and interest Net Amount Recognized credits. Our policy is to fund pension costs by contributing -End of Period $ 743 $ 654 $ (39) $ (38) the minimum amount required by the Employee Retirement Amount Recorded as Income Security Act (ERISA) and additional amounts when Prepaid pension assets $ 184 $ 181 $ - $ -

we deem appropriate. We do not anticipate making a Accrued pension liability (212) (287) (53)- (58) contribution to our qualified pension plans in 2005. Regulatory asset 594 572 ' 11 13 Wsle also maintain supplemental nonqualified, noncontributory, Accumulated other -.

retirement benefit plans for selected management employees. comprehensive loss .139 147 2' 4 Intangible asset 38 41 , 1 .- 3 These plans provide for benefits that supplement those provided

$ 743 $ 654 $ (39) $ (38) by DTE Energy's other retirement plans.

Net pension cost (credit) includes the following components: Assumptions used in determining the projected benefit obligation and net pension costs are listed below:

Qualified Pension Plans Nonqualified Pension Plans (inMillions) 2004 2003 2002 2004 2003 2002 2004 2003 2002 Service Cost S 58 $ 48 $ 43 -S 2 $ 2 $ 1 Projected Benefit Obligation Interest Cost 168 164 162 3 4 3 Discount rate 6.000/% 6.25% 6.75%

Expected Annual increase infuture Return on compensation levels 4.0% 4.0% 4.0%

Plan Assets (216) 1211) (223) - - - Net Pension Costs Amortization of Discount rate 6.25% 6.75% 7.25%

Net loss ;63 38 2 1 1 1 Annual increase infuture Prior service compensation levels 4.0%/6 4.0% 4.0%

cost .8 8 9 - 1 Expected long-term rate of return on Plan assets -9.00/0 9.0% 9.5%

Nettransition asset - - (2) . - - At December 31, 2004, the benefits related to our qualified and non-Net Pension qualified plans expected to be paid in each of the next five years and Cost(Credit) S 81 $ 47 $ (9) 6 $ 7 $ 6 in the aggregate for the five fiscal years thereafter are as follows:

The following table reconciles the obligations, assets and funded inMillions) status of the plans as well as the amounts recognized as prepaid 2005 S. 173 pension cost or pension liability in the consolidated statement of 2006 177 financial position at December 31: 2007 -182 2008 '189 2009 194 2010 - 2014 1,091 66 2004 annual report Total $ 2,006 II

We employ a consistent formal process in determining the SFAS No. 87. The additional minimum pension liability, regulatory long-term rate of return for various asset classes. We evaluate asset, intangible asset and other comprehensive loss are adjusted input from our consultants, including their review of historic in December of each year based on the plans' funded status.

financial market risks and returns and long-term historic We also sponsor defined contribution retirement savings plans.

relationships between the asset classes of equities, fixed income Participation in one of these plans is available to substantially all and other assets, consistent with the widely accepted capital - represented and nonrepresented employees. Wo'e match employee market principle that asset classes with higher volatility generate contributions up to certain predefined limits based upon eligible a greater return over the long-term. Current market factors such compensation, the employee's contribution rate and, in some as inflation, interest rates, asset class risks and asset class returns cases, years of credited service. The cost of these plans was are evaluated and considered before long-term capital market $28 million in 2004, $26 million in 2003 and $25 million in 2002.

assumptions are determined. The long-term portfolio return is Other Postretirement Benefits also established employing a consistent formal process, with due consideration of diversification, active investment management We provide certain postretirement health care and life insurance and rebalancing. Peer data is reviewed to check for reasonableness. benefits for employees who are eligible for these benefits. Our policy is to fund certain trusts to meet our postretirement benefit obliga-We employ a total return investment approach whereby a mix of tions. Separate qualified Voluntary Employees Beneficiary Association equities, fixed income and other investments are used to maximize (VEBA) trusts exist for represented and nonrepresented employees.

the long-term return of plan assets consistent with prudent levels of risk. The intent of this strategy is to minimize plan expenses Net postretirement cost includes the following components:

over the long-term. Risk tolerance is established through fin Millions) 2004 2003 ' 2002 consideration of future plan cash flows, plan funded status, and Service Cost 3$ 41 $ 37 $ 30 corporate financial considerations. The investment portfolio Interest Cost i'92 r 87 78 contains a diversified blend of equity, fixed income and other, Expected Return on Plan Assets (56) 147) (59)

Amortization of investments. Furthermore, equity investments are diversified - Net loss 43 31 3 across U.S. and non-U.S. stocks, growth and value investment styles, Prior service cost (3) (3) (1) and large and small market capitalizations. Other assets such as: Nettransition obligation 8 13 19 private equity and absolute return funds are used judiciously to Net Postretirement Cost S 125$ $ 118 $ 70 enhance long term returns while improving portfolio diversifica--

tion. Derivatives may be used to gain market exposure in an The following table reconciles the obligations, assets and funded status efficient and timely manner; however, derivatives may not be used of the plans including amounts recorded as accrued postretirement cost to leverage the portfolio beyond the market value of the underlying in the consolidated statement of financial position at December 31:

investments. Investment risk is measured and monitored on an (inMWlions) 2004 2003 ongoing basis through annual liability measurements, periodic Measurement Date Nov.30 Dec. 31 asset/liability studies, and quarterly investment portfolio reviews. Accumulated Postretirement Benefit '

Obligation-Beginning of Period S 1=,82 $ 1,494 Our plans' weighted-average asset allocations by asset category Service Cost c-- -41 37 at December 31 were as follows: Interest Cost 92 87 2004 2003 Actuarial Loss '4 146 162 Equity Securities 69%- 67% Plan Amendments 7i (126)

DebtSecurities 26 , 27 Benefits Paid (75) (72) 72 Other 5 6 Accumulated Postretirement Benefit V.1100%- 100%1 Obligation-End of Period $ 1,793 $ 1,582 Our plans' weighted-average asset target allocations by asset Plan Assets at Fair Value-Beginning of Period ,$586 $ 537 category at December 31, 2004 were as follows:

Actual Return on Plan Assets 53 114 Equity Securities 65% Company Contributions 40 -

Debt Securities 28 Benefits Paid - (65)

Other Plan Assets at Fair; Value-End of Period $ '679 $ 586 In December 2002, we recognized an additional minimum pension Funded Status of the Plans- ($11 14Y $ (996) liability as required under SFAS No.: 87, aEmployers'Accounting Unrecognized Net loss -811 705 for Pensions." An additional pension liability may be required Prior service cost Y(8) (27) when the accumulated benefit obligation of the plan exceeds the. Nettransition obligation 58 74 fair value of plan assets. Under SFAS No. 87, we recorded an .- ;; Accrued Postretirement . -X additional minimum pension liability, an intangible asset and Liability at Measurement Date (253)- (244) other comprehensive loss. In 2003, we reclassified $572 million Company Contribution And Benefit Payments in December 2004 (20) of other comprehensive loss related to Detroit Edison's minimum Accrued Postretirement pension liability to a regulatory asset after the MPSC Staff Liability-End of Period $ (273) $ (244) provided an opinion that the MPSC's traditional rate setting process allowed for the recovery of pension costs as measured by 2004 annual report 67

Assumptions used in determining the projected benefit obligation In December 2003, the Medicare Act was signed into law and net benefit costs are listed below which provides for a non-taxable federal subsidy to sponsors I 2004 2003 2002 of retiree health care benefit plans that provide a benefit that Projected Benefit Obligation .; is at least "actuarially equivalent" to the benefit established by Discount rate 6.00 %; 6.25% 6.75% law. As discussed in Note 2, we adopted FSP No. 106-2 in 2004, Net Benefit Costs which provides guidance on the accounting for the Medicare Discount rate 6.250h 6.75% 7.25% Act. As a result of the adoption, our accumulated postretirement Expected long-term rate benefit obligation for the subsidy related to benefits attributed of return on Plan assets 9.0% - 9.0% 9.5%

to past service was reduced by approximately $95 million at Benefit costs were calculated assuming health care cost trend January 1, 2004 and was accounted for as an actuarial gain.

rates beginning at 9.0% for 2005 and decreasing to 5.0% in 2010 The effects of the subsidy reduced net periodic postretirement and thereafter for persons under age 65 and decreasing from benefit costs by $16 million in 2004. The impact of the Medicare 8.0% to 5.0% for persons age 65 and over. Aone-percentage-point Act on the components of other postretirement benefit costs increase in health care cost trend rates would have increased the for the year ended December 31 was as follows:

total service cost and interest cost components of benefit costs (inMillions) by $20 million and increased the accumulated benefit obligation Reduction inservice cost $ 2 by $177 million at December 31, 2004. Aone-percentage-point Reduction ininterest cost . 6 decrease in the health care cost trend rates would have decreased Amortization of actuarial gain .

the total service and interest cost components of benefit costs by Decrease inpostretirement benefit cost $ 16

$17 million and would have decreased the accumulated benefit At December 31, 2004, the gross amount of federal subsidies obligation by $157 million at December 31, 2004. expected to be received in each of the next five years and in the Effective 2005, we amended our postretirement health care plan aggregate for the five fiscal years thereafter was as follows:

to provide for some enhancements. The changes increased our ain Millions) expected 2005 postretirement cost by $6million. 2005 $ -

2006 11 At December 31, 2004, the benefits expected to be paid, including 2007 1-prescription drug benefits, in each of the next five years and in the 2008 12 2009 12 aggregate for the five fiscal years thereafter are as follows: 2010- 2014 69 ranMilions) Total $ 115 2005 . 97 2006 106 Grantor Trust 2007 110 2008 113 MichCon maintains a Grantor Trust that invests in life insurance 2009 120 contracts and income securities. Employees and retirees have 2010 - 2014 ' 665 no right, title or interest in the assets of the Grantor Trust, and Total $ 1,211 MichCon can revoke the trust subject to providing the MPSC The process used in determining the long-term rate of return for with prior notification. We account for our investment at fair assets and the investment approach for our other postretirement value with unrealized gains and losses recorded to earnings.

benefits plans is similar to those previously described for our qualified pension plans. NOTE-15 STOCK-BASED COMPENSATION Our plans' weighted-average asset allocations by asset The DTE Energy Stock Incentive Plan permits the grant of category at December 31 were as follows: incentive stock options, non-qualifying stock options, stock

_2004 2003 awards, performance shares and performance units. A maximum Equity Securities 68%- 66% of 18 million shares of common stock may be issued under the Debt Securities 28- 30 plan. Participants in the plan include our employees and Other 4 4 members of our Board of Directors. As of December 31, 2004, 100%--, 100%

no performance units have been granted under the plan.

Our plans' weighted-average asset target allocations by asset Options category at December 31, 2004 were as follows:

Options are exercisable according to the terms of the individual Equity Securities 65%

Debt Securities 28 stock option award agreements and expire 10 years after the date Other 1 of the grant. The option exercise price equals the fair value of

.100% the stock on the date that the option was granted. Stock option activity was as follows:

68 2004 annual report 11

Weighted The cost is amortized to compensation expense over the vesting Number of Average period. Stock award activity for the years ended December 31 was:

Options Exercise Price Outstanding at December 31, 2001 2004 2003 2002 (1,678,870 exercisable) 5,281,624 $ 38.51 Restricted common shares awarded I 209,650 102,060 113,410 Granted 1,334,370 $ 42.08 Weighted average market Exercised (678,715) $ 34.64 priceofsharesawarded IS 39.95. $ 41.39 $ 42.92 Canceled (456,684) $ 38.74 Compensation cost charged Outstanding at December 31,2002 against income (in thousands) $ 5,616 $ 6,366 $ 4,101 (2,285,323 exercisable) 5,480,595 $ 39.87 Granted 1,654,879 $ 40.56 Performance Share Awards Exercised (329,528) $ 35.88 Performance shares awarded under the plan are for a specified Canceled (152,824) $ 42.67 number of shares of common stock that entitles the holder to Outstanding at December 31, 2003 ia = - receive a cash payment, shares of common stock or a combination (3,506,038 exercisable) r, 6,653,122 . $40.18 - thereof. The final value of the award is determined by the achieve-Granted j 1,3 00,9OO $S3941 ment of certain performance objectives. The awards vest at the Exercised j^ ; (891,353) $34.94F end of a specified period, usually three years. We account for Canceled . (356,00) 4306 performance share awards by accruing compensation expense Outstanding at December 31, 2004 (3,939,939 exercisable at a weighted - over the vesting period based on: (i) the number of shares average exercise price of $40.52) 6,706,669 - 4057 expected to be paid which is based on the probable achievement of performance objectives; and (ii)the fair value of the shares.

The number, weighted average exercise price and weighted average For 2004,2003 and 2002, we recorded compensation expense remaining contractual life of options outstanding were as follows: totaling $6.1 million, $5.5 million and $3.6 million, respectively.

Weighted Weighted Average Range of Number of Average Remaining During the vesting period, the recipient of a performance share Exercise Prices Options Exercise Price Contractual Life award has no shareholder rights. However, recipients will be paid

$27.62-$38.04 649,604 $ 31.70 5.02 years an amount equal to the dividend equivalent on such shares.

$38.60- $42.44 4,594,837 $ 40.68 7.65 years Performance share awards are nontransferable and are subject to

$42.60-$44.54 690,950 $ 42.70 6.38 years risk of forfeiture. As of December 31, 2004, there were 619,044

$45.28-$46.74 771,278 $ 45.47 6.51 years performance share awards outstanding.

6,706,669 $ 40.57 7.13 years W&e account for option awards under APB Opinion 25. Accordingly, NOTE-16 SEGMENT AND RELATED INFORMATION no compensation expense has been recorded for options granted. We operate our businesses through three strategic business units As required by SFAS No. 123, we have determined the fair value for (Energy Resources, Energy Distribution and Energy Gas). Each these options at the date of grant using a Black-Scholes based business unit has utility and non-utility operations. The balance of option pricing model and the following assumptions: our business consists of Corporate &Other. Based on this structure, 2004 2003 2002 we set strategic goals, allocate resources and evaluate performance.

Risk-free interest rate 3.55% 2.93 % 5.33 %

This results in the following reportable segments.

Dividend yield 523% 4.97 % 4.90% Energy Resources Expected volatility 20.89 % 19.79 %

Utility -Power Generation operations include the power Expected life 6 years 6years 6 years - generation services of Detroit Edison, the company's Fair value per option -$4.46 $4.78 $6.25 electric utility. Electricity is generated from Detroit Edison's Stock Awards numerous fossil plants or its nuclear plant and sold throughout Southeastern Michigan to residential, commercial, industrial Stock awards granted under the plan are restricted for varying and wholesale customers.

periods, which are generally for three years. Participants have all rights of a shareholder with respect to a stock award, including

Non-utility the right to receive dividends and vote the shares.; Prior to vesting -Energy Services is comprised of various businesses that develop, in stock awards, the participant: (i) may not sell, transfer, pledge, acquire and manage energy-related assets and services. Such exchange or otherwise dispose of shares; (ii) shall not retain projects include coke production, synfuels production, on-site custody of the share certificates; and (iii) will deliver to us a energy projects and merchant generation facilities.

stock power with respect to each stock award. -EnergyAarketing & rading consists of the electric and The stock awards are recorded at cost that approximates fair value gas marketing and trading operations of DTE Energy frading on the date of grant. We account for stock awards as unearned Company and the natural gas marketing and trading compensation, which is recorded as a reduction to common stock. operations of DTE Enterprises. Energy Marketing &Trading enters into forwards, futures, swaps and option contracts as part of its trading strategy.

- OtherNon-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 Corporate&Other includes administrative and general expenses,

Utility -Power Distributionoperations include the electric and interest costs of DTE Energy corporate that have not been distribution services of Detroit Edison. Energy Distribution allocated to the utility and non-utility businesses. Corporate &

distributes electricity generated by Energy Resources and Other also includes various other non-utility operations, including alternative energy suppliers to Detroit Edison's 2.1 million investments in new emerging energy technologies.

residential, commercial and industrial customers. The income tax provisions or benefits of DTE Energy's subsidiaries

Non-utility operations include businesses that assemble, are determined on an individual company basis and recognize the market, distribute and service a broad portfolio of distributed tax benefit of Section 29 tax credits and net operating losses. The generation products, provides application engineering, and subsidiaries record income tax payable to or receivable from DTE monitors and manages system operations. Energy resulting from the inclusion of its taxable income or loss in DTE Energy's consolidated tax return. Inter-segment revenues Energy Gas primarily consist of power sales, gas sales and coal transportation

Utility operations include gas distribution services provided services between Energy Resources Utility-Power Generation, by MichCon, the company's gas utility that purchases, stores Energy Services, Energy Marketing &Trading and Non-utility and distributes natural gas throughout Michigan to 1.2 million Other, and Energy Gas-Non-utility. DTE Energy's interest income residential, commercial and industrial customers. totaled $55 million in 2004, $37 million in 2003 and $29 million in

Non-utility operations include the production of gas and the gather- 2002, and is primarily associated with the Energy Services and ing, processing and storing of gas. Certain pipeline and storage Corporate &Other segments. Financial data of the business assets are supported by the Energy Marketing &rTading segment 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) (12) 9 - -

Total $ 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) 68 14 Cumulative Effect of Accounting Changes (27) 127) 68 -

Total S521 $20.753 $2.067 $ 751 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) 46 63Z 44 109 Total $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).

(inMillions, exceptpershare amoun1s)

= - S} .

Operating Revenues - 2093W $ 1.501I$ *$ 1,594 $ 1926 1114 Operating Income $

S368 $ 9 - 173 S 210 $ 84$

Net Income (Loss) : -

From continuing operations $ 197 . S35 S - 93 1 Ila 4 3 Discontinued operations (7) - - (5) (12)

Total 190'> Sr 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$- . $0 S- .546 :$ -55 j.6 Discontinued operations (0.04) - - - (.03) - - .06)

Total $ 1.11 .20 S - .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) - - - (.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) - - _ (.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 ispresented for informational purposes only. The Gas Wlity business was acquired on May 31, 2001.

(3)Inconjunction with adopting SFAS No. 143, we reclassified previously accrued asset removal costs related to our regulated operations, which had been previously netted against accumulated depreciation, to an asset removal cost liability for the years 1999 through 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 Section 29 Tax Credits Raw coal is heated to high temperatures in ovens to drive Tax credits authorized under Section 29 of the Internal Revenue off impurities, leaving a carbon residue called coke. Coke is Code, designed to stimulate investment in and development of combined with iron ore to create a high metallic iron that is alternative fuel sources. The amount of a Section 29 tax credit can used to produce steel. A series vary each year as determined by the Internal Revenue Service.

of coke ovens configured in a module is referred to as a battery.

Securitization I Detroit Edison financed specific stranded costs Customer Choice at lower interest rates through the sale of rate

_ _The customer choice programs reduction bonds by a wholly owned special purpose are statewide initiatives giving entity, the Detroit Edison Securitization Funding LLC.

t customers in Michigan the option to choose alternative suppliers for electricity and gas.

Stranded Costs Costs incurred by utilities in order to serve customers in a regulated environment that absent special regulatory approval Gas Cost Recovery (GCR) Mechanism would not otherwise expect to be recoverable if customers A GCR mechanism authorized by the MPSC permitting switch to alternative suppliers of electricity and gas.

MichCon to pass the cost of natural gas to its customers.

Synfuel MPSC The fuel produced through a process involving chemically The Michigan Public Service Commision regulates modifying and binding particles of coal. Synfuels are used for the state's energy, telecommunications and power generation and coke production. Synfuel production transportation services industries. generates Section 29 tax credits.

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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BUSINESS REPLY MAIL : UNITED STATES FIRST-CLASS MAIL PERMIT NO. 61 DETROIT Ml POSTAGE WILL BE PAID BYTHE ADDRESSEE ATTNWRITING RESOURCES 1571 WCB DTE ENERGY 2000 2ND AVE.

DETROIT Ml 48226-9886 Ii tttlliilmnliliiliiilltililgiliiltliiliilliiliiill

overview form 10-K DTE Energy's common stock is listed on the New York Stock We will provide, without charge to shareholders, copies Exchange and the Chicago Stock Exchange (symbol DTE). of our Form 10-K filed with the Securities and Exchange The following table indicates the reported high and low sale Commission. Written requests should be directed to:

prices on the New York Stock Exchange Composite Tape for Susan M.Beale DTE Energy common stock, and dividends paid per share for Vice President and Corporate Secretary each quarterly period during the past two years: DTE Energy, 2000 Second Ave.

Detroit, MI 48226-1279 Calendar Quarter High Low PerShare or dteenergy.com/investors 2004 First $ 42.29 ; 37.92 $ 0.515 officer certifications Second 41.58 37.88 0.515 In 2004, our chief executive officer (CEO) submitted to the Third 42.21 39.31 0.515 New York Stock Exchange (NYSE) the annual CEO certification Fourth 45.49 41.44 0.515 regarding DTE Energy's compliance 2003 First $ 49.50 S 38.51 $ 0.515 with the NYSE's corporate governance Second 44.95 38.52 0.515 listing standards, stating that he was Third 38.98 34.00 0.515 Fourth 39.76 35.12 0.515 not aware of any violation to the NYSE corporate governance listing standards. ,

As of Dec. 31, 2004, 174,209,034 shares of the company's Our CEO made his annual certification common stock were outstanding. These shares were held to the NYSE as of May 27, 2004. In by a total of 99,832 shareholders of record. addition, we have filed as exhibits to 1 distribution of ownership of DTE Energy the Annual Report on Form 10-K with' common stock as of Dec. 31, 2004: the Securities and Exchange Commission, the certifications Type of Owner Owners Shares required under Section 302 of the Individuals 40,889 12,636,138 Sarbanes-Oxley Act of 2002 regarding the quality of the Joint Accounts 37,363 15,385,259 company's public disclosures in the fiscal year-end 2004 reports.

Trust Accounts 1,468 1,047,942 Nominees 38 136,597,601 transfer agent Institutons/Foundations 40 40,651 The Bank of New York Brokers/Security Dealers 46 30,529 Others 19,988 8,469,914 Send certificates for transfer and address changes to:

Total 99,832 174,209,034 Receive and Deliver Department, P.O. Box 11002 Church Street Station, New York, NY 10286 State and Country Owners Shares Telephone: 866.388.8558 www.stockbny.com Michigan 51,494 20,538,997 Florida 5,941 2,653,067 registrar of stock and other information California 4,903 1,703,692 *Addressshareholder inquiries to:

New York 3,908 137,904,170 The Bank of New York, Shareholder Relations Department Illinois 3,765 1,380,697 P.O. Box 11258, Church Street Station, New York, NY 10286 Ohio 3,111 1,029,857 or e-mail inquires to: shareowners@bankofny.com 44 other states 26,300 8,865,125 Foreign countries 410 133,429 As a service to shareholders of record, DTE Energy offers direct Total 99,832 , 174,209,034 deposit of dividend payments through The Bank of New York.

Payments can be electronically transferred directly to the bank annual meeting of shareholders or savings and loan account of choice on the payment date.

The 2005 Annual Meeting of DTE Energy Shareholders will Write to the address above, or call 866.388.8558 to request a be held Thursday, April 28, 2005, at 10 a.m. (EST) in the Direct Deposit Authorization Form.

DTE Energy Building, 660 Plaza Drive, Detroit, MI. Shareholders of record can elect to receive future copies of corporate address our Annual Report and Proxy Statement electronically by DTE Energy, 2000 Second Ave. marking the appropriate box on their proxy card as instructed.

Detroit, MI 48226-1279 By electing electronic delivery, you are stating that you Telephone: 313.235.4000 dteenergy.com currently have or expect to have access to the Internet.

independent registered public accounting firm T 2005 DITEEnergy is the owner Printed by St Ives Inc Deloitte & Touche LLP D rTETEEnergy Company, of the THead'Corona" Miami, Fla, I I all 1rights reserved. logo. DTE Energy or 600 Renaissance Center, Suite 900 its affiliates are the Detroit, MI 48243-1704 NYSE owners of various other registered and unregistered trademarks.

2004 annual report 77

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