Text

Annual Financial Report
	ML061230553
Person / Time
Site:	Fermi
Issue date:	04/24/2006
From:	Gaston R; Detroit Edison
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	NRC-06-0035
	Download: ML061230553 (89)
	v • d • e

Fermi 2 6400 North Dixie Hwy., Newport, MI 48166 Detroit Edison 10 CFR 50.71(b)

April 24, 2006 NRC-06-0035 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 2005 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) 586-5197.

Sincerely, Ronald W. Gaston Manager, Nuclear Licensing Enclosure cc: wfEnclosure D. H. Jaffe T. J. Kozak NRC Resident Office Regional Administrator, Region III Supervisor, Electric Operators, Michigan Public Service Commission A DTE Energy Company

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ENERGY IS OUR

-v Foundation, Focus, Future Tableof Cttents 1 ttik Utility 3"4~ e4 ; Detroit Edison Detroit Edison generates, distributes and sells electricity to approximately 2.2 million customers in southeastern Michigan. The 5

JOji*Ti,' company uses coal, nuclear fuel, oil, natural gas and hydroelectric pumped storage to generate its electrical output.

We also purchase electricity from other

<46w generators, suppliers and wholesalers.

Founded in 1903, Detroit Edison is the LI Y largest electric utility in Michigan and the 10th largest in the nation.

MichCon 80' MichCon is engaged in the purchase, storage, transmission, distribution and I- --- - ------- - -

3/4' 1

Energy Is S.;- - our business V

I sale of natural gas to approximately 1.3 million customers in Michigan.

to select energy-intensive industries. Ventures include Fuel Transportation and Marketing MichCon owns and operates 271 on-site energy projects, storage wells representing industrial scale generation We leverage our large approximately 34 percent of the and cogeneration, physical energy asset base underground working capacity and biomass projects. to market and transport gas, in Michigan. There is more coal and power to customers.

capacity in Michigan than in any We are one of the largest Unconventional Gas marketers and transporters of other state. Founded in 1849, Production coal to third-party customers in MichCon is the nation's 11th largest natural gas utility. Unconventional gas production North America. We are a comes from drilling in shale and leader in gas storage and coal seams. DTE Energy produces regional pipeline operations.

Power and unconventional gas in northern We market and trade energy.

Industrial Projects Michigan's Antrim Shale and has Our power and industrial projects expanded its business into the provide private, utility-type services Barnett Shale inTexas.

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I It Financial Highlights j

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,<:i.-(Doflars~ in Milflions, Ex.etPrShar bnS~ 3 <: 7 05204 %Cange i i Electric Utility - $ 4,462 $ 3,568 -25.1% ,;-;

Gas Utility 2,138 1,682 27.1 /

Non-Utility 3,114 2,425 28.4 /.

Corporate & Otheer_..'

.41.2/

Eliminations tn!

' (702) i621) N/A /a~

9,022 - $ 7,071', 27.6 Elebctric6 UtiIity: $ .277 $ .150 84.7 37 - 20 85.0 O'D-~- ~" '""

GGas Utility'- 3.6V Cu mu V 3114 (52) 3" 303 (12) N/A%

Corporate& tr 576 461 . 24.9 DiscontinuedOperations I (36) (30)3 - 20.0. %C, - ,,

Cml ati v Ef e t f c un ng C a es (3) -

$ 537 $ 431 24.6 %-/

I, - . I - I . _ J .. L =L__L___

, 1.57 , $ 0.87

'31 0.21 o',l.

0.1 Non-Utility I= ,1.78., ; j - 1.75;

'.Corporate & Other . :i00,,XfJ~R'-- (0.29) (0.07).

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,-.~+r3.21 j ,i -,1 -,2.66 ^ 22.5 %

Discontinued Operations-:,,,',-, (0.20) ((0.17):

- Cumulative Effect of Accounting Changes (0.02) -

$ 3.05 - $ 2.49 1.7/

Dividenrds Declared Per Share,',-,,,,.r '-=,

,",, 206 2.$ $ 2.06 1

j'JI Dividend Yield;`-' , ;` %_,..- , 8 * -4.8 i

-Average Common Share's Outstanding (Millions 225 1: 11 I II. - - Basic>' '175 173, Diluted 176 `--173 Book Value Per Share .-, $ 32.44 S 31.85

': Market Price at Year End ' $ 43.19 $ 43.13

.Total Market Capitalization-. ;$ 7,680, - $ 7,514 I -

178%

,Capital Ependitures - $, 1.065 $ 904

-Total Assets--' .. ,,.:' - 23,335 $ 21,297 96/

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... $.1972 1.1978 1984' -- 1990i 1996 2002a.. 2005 1995 1997 -1999. , 2001'`' 2003 200 DTE7 EnergyAnn ual Dividen -^ .fcd . .D Dividen 'd di d Pad Pad S&P S P El cri trdr nd x v. DT ne g

'We'have paid an annual dividend to We have consistently paid an annual

- shah for h past96 yearseho dided while others have Cut th 3 ' '

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Shreolers a__ -

Energy is our business T *Y ri-6 2 m i;;o n --..

lan'dscapcontinues,...

to -evolv cretingi I,>- r I5*;-i se;fiw

-.multitude' 'fo-pj" nit es~-

and challeenges fo Thur industry aidne Y' " I

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~'-Web e ieve -energyilS incteasinglve beoea a su p res, , busins ial:;* ;;7-: fi'

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.wi I handful f -rre playrsg DTE Energy intends to be among the top DTE Energy Chairman and competitors. Our utilities provide a solid Chief Executive Officer Tony Earley.

foundation with more than a century of service to our customers. We continue to I expected 2005 to be a rebound year and it was.

build on this rich heritage. A focused Our 2005 diluted earnings per share were $3.05 portfolio of energy-related non-utility compared to $2.49 in 2004, a 22.5 percent increase.

businesses allows us to leverage our utility Reflected in these results was the improved expertise and broaden our reach. This strong financial performance of ourtwo utilities. Rate business mix, coupled with a disciplined increases authorized for both Detroit Edison and

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growth strategy, positions us well to MichCon had a major impact on our bottom line.

respond to the changing marketplace. So did the favorable weather.

I_______-<* -- ,,' - *-'.'

Letter to Shareholders I believe both utilities are poised to grow at businesses through 2008. We expect this a level we have not seen for two or three cash will be generated primarily from synfuel decades. Combined, their earnings could tax credits, assuming the tax credits are not increase 5 percent annually through 2010. phased out and sufficient taxable income To achieve this we must: exists to use the credits. The phase out of credits depends on the price of oil.

Continue the good progress we're making to establish a constructive regulatory We're focused on three core non-utility environment in Michigan. business segments: power and industrial projects, unconventional gas production, and fuel transportation and marketing. Each segment has the potential to produce net income of $50 million to $100 million by 2008.

In 2005, we made good progress. We closed four on-site energy transactions. We began operating our first petroleum coke processing plant. We acquired three landfill gas recovery projects in two states. We substantially ramped up our Barnett Shale business.

We expanded our gas storage and pipeline capacity.

To build on our progress, in 2006 we are focused on significantly improving our cost profile and our operating performance. We believe that across the board top quartile performance will not only improve our DTE Energy is a leader in keyhole technology designed to bottom line, but will also help us respond minimize gas leak repair time and costs. Fitters Fred Drys (left) and Alphonso Hill. appropriately to the changes occurring in our industry.

Complete a series of utility investments Our ultimate goal is to provide superior that will increase the asset base on which service to our customers and premium we earn the 11 percent allowed return. returns to our shareholders. As we worked (These investments are reviewed later through our regulatory issues in 2004 in this report.) and 2005, our shareholder returns were

Lower costs and streamline disappointing. Now we are ready to reap the value we have developed at DTE Energy.

processes through our Performance Excellence Process. Thank you for your continued support as we build an exciting future for your company.

One caveat to this generally positive picture is Michigan's economy. A return to more Sincerely, robust levels would give the company more growth opportunities.

Anthony F.Earley Jr.

Our non-utility businesses also are on a Chairman and Chief Executive Officer growth trajectory. We plan to redeploy approximately $1 billion of cash to build these March 1, 2006 4

>i2'4~;A;'~z'industry evoling-and-what;--DTE Ener y'isding Jo se' ure ';-5

< ;-,:';';..ts'sfutuwea r' rofideer'weha'e te'-rght ap rch'

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N D- e os4 the ire 4-c- ane o n g 444 r ace it future'., We.a' cofien we hav th righ.'t approach0

-=i;-D clean ar-concerns' and th e csIiaM '~ f ypoeaebillionso :6 tininvesmens to meetm andae4 ' 4missios ovr erthnex 4targets '. -sever iars:he E~~nergwcmanies avastrangeutblnetete ol requir benuho eddsdmn wn e tao ener gis 4- . 4 -

oe TRND.. , - tesnvirn ia oer adanede nvironmental controls ;

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..Li: ----e t"- 'i' i'-'6 a c pe sacean att of co 4 :;r, 4;kei.;-=X=

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- t DTo E Esntenrgytwe hnVet aleig,and proudghistovern years. Ti vs rangieri' of requirnementsa siu rdsidean will acclre ofctLvitu inm- fnent.-, 44

-- ' is '7-- .' . ceadentean Chief other aneratin rr nede onc tachoi rols, 7ir ' . ; 4 Off, . rry = . -c- - t

.- - .n-;r;nmental committee of the Edison Electrc Institute. :He also chairs the Michigan Greenways Initiative and is vice chair-of .The Michigan Nature Conservancy board o ,

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'-' Nearly 500 Detroit Edison and contract 7V i. . , ..

line workers, tree trimrners and support --

personnel assisted electric utilities -

in Louisiana and Mississippi during - '

-::, -n ` il X\ - N-- `, - hurricane relief efforts. Logging more - -

~~than 3,200 mileisiand 21,600 hours0.00694 days 0.167 hours 9.920635e-4 weeks 2.283e-4 months of labr' Detroit Edison crews helped restore'

.::, I !#t \ - power and clear debris-7-7

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ENERGY IS OUR Foundation, Focus, Future TREND Eniom na cntinued),.,

ta aropeatins an impact:

e reognze theenvromen~ Ad rsosay7 That's why harto seour reores efficiently, we~or avancd tchnologies, 6dfn embrce deane waysjtogenerate power(

ro ex i, ese morie tha $49oriilint Ov otnetecto a a ae co 1Weuie se usion roem more SC a MinoeiMollunroeoid2 scrbbrsatalsoouaprgcoroir SCR at Monr isany'sunfitsdi(xieC&rig th'A o_-n Page 8.) -The company plan's to ,

spen aproiately $218, mi~ll6r6iln 2006' a7nd U13to an-additional $2.2, billion in future cptlex Andiiu`is~tfirbug h 2018 tofmeet'

,,eemissionreduction reqluirements-, 4 we aracive on; manyjfro'nts.

Ou0r fossil-fuel plants burnlnearly 60,000' .

~ton of cal e'a"ch day;,of Whicl about', v ~ - ~

`JO7 percentis btihing low-sulfur~ i b-aie

~westerni coaI J Our. electricjutilitya oe of the first to use this,coa to.significantl Vrducs Ijfurdioxide'emission We're alis' looing'at ways to reduce,

\nI~~ecury.&emissions:lWhen fully operational,,.,

'h 'd 'r teSCRs and scubbrs' at the Monroe\I

~P6owerPlantwillrerrovethedmajority-~'

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\w]7 Josh Ackerman at the M ontome ' rA AN- landfill-gas collection system owned and operated by, DTE Biomiass Energy.

ENERGY IS OUR Foundation, Focus, Future more than 95 percent of Wrefocusing the construiction of ne~w emission controlav 2 equinpment at Monroe Power Plant- Detroit Edison's largest plant--:-

sulfur dioxide emissions. .- with a capacity of more thanh3,WO(megawatts..Dan Fahrer(left '

The scrubbersproduce a engineering manager, environmental projects, and Sam Dubois, construction supervisor.

gypsum byproduct that can be marketed and sold to -'; --TREND: Environmental: (ontinued) wallboardcompaniesfor use N I a i th ss l argestsource O emissions free in making theirpproducts.

electricity. '

In addition, the scrubber "Today nuclear power is safer, *cleaner.and more project will create 450 new efficient han ever before,' says DTE Energy construction trade jobs in '..Ch'airan and Chief Executive OfficerTony Earley, the metropolitan '-'wh'o al serves as' 2006 chairman of'the Nuclear

'Energy Institute..-Environmental concerns will Detroit area I drive 'arenaissance of nucle.r power in ouri h r '

country and eventually, in Michigan, too Our Fermi 2.nuclear power plant provided 18 percent of Detroit Edison's total electric jZ X--j.,r-.

'generationr in 2005, with virtually no air emissions In fact, since we began operating Fermi 2 in 1987 8

7, -4 ENERGY IS OUR Foundation, Focus, Future

--TREND: Volatile Prices (continued)-

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We're

< lincreasing natural- 7 gas-producti'on..

"In the.long-term,.supplies ofnatural-_I ..

gas must increase if we are to redule.

r customers' bills'meaningfuill'y" T

-according toSteve.EwingDTE Energy'-

vice chairman and 2006 chairman of

-the American Gas-Association-.1n-testimony before C5ongress, ast fall,.....<

- - Ewing urged our nation's policy-makers

-to take decisive action now to solve.the:.<.,,i E supply problem.

At DTE Energy we're doing our pa AA Antrim Shale formation: With mor -

Ti~i2,000 producing-%v~ellss~

'approximateK30y 00icresw

-roduce enoug

_4-formation to heat183,000 homes.

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fafull y6a'ear.' We-drill' about-125 nw -

.we llss per year and expect the Antrimi' H330basin to kep pro ucing.fbrfanother-i,

-previosy~

yvears.MWe'ret-alsotpiinig into jfA inacess ea- tt-A Shale with ho otal driling technologj \I I AntEiim hroughx'tero 0ng position in i Shale5wel.2ha expanhded 6.e o-iff ffrts gas.t6 a, al~~n~jo

~M rii"Jf1,0 foirriationi,~th6113arnett'sle-$

Z,,..eod Wo art,Texa- We nearFort o~hTxsW'u rrentI erly,75,000 leaseholdacres wittpan exad-Wehave<14-apxmateIy,60 prdducin6~wells i.

t hv theBarnet Sh-ale,-'and plan 't6 -. .drill'~

-ditoa 55wlsin.2O0~9~

10

We're increasing gas storage and pipeline capacity.

We are the second largest gas storage provider in the Midwest. We store gas for our own utility, MichCon, as well as for energy providers across the Midwest and Northeast.

A $45 million expansion of ourWashington 10 storage field north of Detroit, will help us move gas supply to the growing Northeast market.

We're planning to expand a second storage field in 2007 and open a new field by 2008. This will give us additional opportunities to store gas for third parties.

We're investing $25 million to expand the Vector pipeline, which moves natural gas from Chicago through Michigan to Dawn, Ontario, and is connected to Washington 10.

We're also partners in developing the Millennium pipeline which, when built, will move gas from Michigan's storage fields, through Ontario into Western NewYork and NewYork City. Construction should begin in late 2006, with the pipeline operational by November 2007.

Both the storage and pipeline expansion projects will help strengthen our gas distribution business.

Coal powers more than half the nation's electric supply.

The National Energy Information Center forecasts coal demand will increase 38 percent over the next two decades, with more than 90 percent of that coal sold to utilities.

DTE Energy is among the nation's top three North American coal marketers and transporters. We specialize in efficient management of coal supply and transportation, moving nearly 40 million tons of coal across the country, in addition to Detroit Edison's 21 million tons. We're looking at opportunities to expand this position.

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ENERGY IS OUR Foundation, Focus, Future i

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'-We helpjlarge indlustrial >-

cu sto m ers -conserve:

energy and 'cut osts

-Heavy energy. users served by-our, '

.electr-utility, Detroit Edison, can

-- r- e _'-- iprogram called of a .

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,- ,, -J-. - > 4j , ,,;%

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customers materially improve.alifaround'.

-. efficiency, and achieve b6tt'omlfine.r.results.-

, .- tx - - K- -. - s *g We also develop,.own and operate.{ --.-

a variety of orinii6eenergy projects -

. through one of our non-utility subsidiaries I'~

Itserves customers: at 24 sites across the.

country. inthe auto,'steel, pulp and paper,'

_.food processing and airport segments

-These projects include operating,.:

',powerhouses backup generation, h'eatingI

,and coohng systems, and waste-water..

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ENERGY IS OUR Foundation, Focus, Future 1, - .1 I .

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.Tvth nearly a , -- v, A

- M quartgr-millioncustomers, M

> Granh Rapids, Mich.,

'ranks,as MichCon's second'

-largesltservice region.:Add-1.

a-recelntly built highway,--

hospital and heaithtcomplex, and GrandRapids becomes I 'I'll - - ,

a thriving market,' "

with rapidlygrowing 1UL infrastructureneeds.'

The Jamestown Pipeline,

' 28 miillsof 30-inch'

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steel piping, will meet Surveingte Jamnestown Pipeline inGrand Rapids. Mich.,-- . N ;- j,ej: .2 -. .

2 market demand. When are Jerry Belarid (left), man~ager of piublic imrprove-ment and, ; -

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complete, it will allow n-and construction.-

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MichCon to spply naturalgas to 220,000 ._-TREND: stuCtur1 *,

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, r ;^Jry ean (conitinuedd) lftmaaero imprrovnetad.

pbi residentialcustomers. . r- > rt,,+ \* ,

MichCon M-- atracts approximiately 17,d000" : ,,

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nerseachyea. As aresult of this" jk _

growth,'we're installing anew natura gas

...E. ;4 p ipeline n ea Grand Rappid Michigdn. constructio (ee "In the Pipeline:' left.)

to seve weste rn

,will begin this! ring.

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.ia ,; ; i.+t.-,i; Inras ructure investments at oth our utilities

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,ncreases their rate bases, g ,vi v i ng t_. it E dison,' -tes S6 t t rJ i 4 aa jr s and MichCon a the opporunity to grow, while` .1 a, . j - Lsv

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helping to power Michig.an's aesno TlSy.: :-!, ' e C ' ; ' .

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TREND: Industry Consolidation ,'-WHENCRDTIDU As our industry evolves, we believe there will D TYEEergyrdce t uncletbs be fewer, but larger energy companies with broader geographic service boundaries. ~1pexpense7prntionyarb usingtheDT nery Oearating -

Our goal is to be among the top 25 percent of all U.S.-based energy companies in System. A ross-utinlea terms of customer satisfaction, operational of employees jozned the Credit &

CGoHe ctionsd pdt ient~to-create a performance and cost. We are striving for excellence and have an aggressive program morerobut prcessfor ~idehtfyn to get there. It is focused on: ovedu bllsan cmmunicatn 1.Improving the efficiency of our operations and reducing costs across the board; and 2.Growing our businesses to achieve greater scale and scope.

We are striving to simplify work, remove roadblocks and reduce costs.

In the fourth quarter of 2005, we stepped up our efforts to help prepare DTE Energy for the large slate of investments we plan to make during the next five years to grow our businesses. Customers, too, will benefit from our work to keep down our costs and their rates.

The DTE Energy Operating System is a powerful tool we're using to implement the ...Credit Cr and Collection Specialist Daderriel Warren i 'It Wad and r ji t'-.t.[14r i Srei5::*dj dramatic change required. (See "When Credit ;%<, t his supervisor, Atesia Smith.- - .,

Is Due,' right.) For example, employees at the Electric MeterTesting and Calibration Center ;,aquickly ihCsoesusn.a:w-jr.-- i,.Mn achieved dramatic results by applying k,.process. ..Soon after ,customers are Operating System tools to their work

'overdue,atanautomaticcallreminds processes. Before the re-engineering effort, each worker refurbished 40 meters per day at themrto pay. their bll. Eventually, a cost of $12 per meter. Today each worker '.unpaid bills'are turned over.to-a-. ,..-; E.=

produces an astounding 110 meters daily for collection agency. Gustomers have S.

about $4 per meter. said theapprecite'thefi .

Improvements like this get us closer to ,-Xreminder and, after just one call, our vision of becoming a top-performing are more'likely to pay their bills7By company; providing superior service to our )'1.ptakingproactive steps to address the customers and premium returns to our nthecompanyghas increased shareholders; and positioning ourselves ;;fz*sf

-pro blrn the . o i 2 -

Oc`ishflow ,by,$20 . milin ,'.

for long-term earnings growth.

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ENERGY IS OUR Foundation, Focus, Future A SOLID FOUNDATION '

-'--TheDTE-Energyl'i,,',,

hFoundation awarded morex,

.:than$7; million- grantstoto

,f in ;

nopoft organizations "'~1-~-.:

nit wil once again rcgnz withA, chievtng-Excellece:-e Awards.. Awlard 'wil be> <'

presellted in-olla 'aoktidi leadership, sustainability and special achievement.

Past winners have included the Detroit Science Center,' -

the Southwest Detroitsl-. "-- " '

Business Association and, the Community%,Fundation..

of the UpperPeninsula.

-TheAchieving Excellence Awards recognize"'~A exemplary nonprofit organizations,notjustf fori

.:;what they do; but for ho well they do It

-.: .~.The DTE Energy Foundation awards grants

--under its 7LEAD guidelines leadership' education, environment.

a chiev'ement development and diversity. The Detroit' Science Center isa past grant recipient 16

Bob Buckler (right), Detroit Edison president and chief operating officer, 'served ascairm an of the Detroit Super Bowl XL IHost Committee Downtown*

Plain~in Team. With him isRoger Penske, chairman II Bo tuch DtritSu per Bowl XL Host Com ittee.

We provide more than 10,000 jobs in Th'e future -isfilled with:J ,5 r'< i Michigan. We strengthen communities through the DTE Energy Foundation. (See "A Solid opportunity.- We intendto.

Foundation' left.) In 2005, our employees and :wmake the most of it.

retirees pledged $1.7 million to the United Way campaign and $189,000 to Hurricane Katrina As our industry evolves, so does relief efforts. Hundreds of employees hold -DTE Energy. We believe we have what leadership positions in the community. .it takes to-be a successful company:

Among them are Joyce Hayes-Giles, our Astrong foundation senior vice president of customer service, who -*Aprovenstrategy is vice president of the Detroit School Board.

A complementary business mix; Lineman Jim Beaubien is mayor of Gibraltar, Mich. Bea Denard, the human resources

A dynamic leadership team director for our energy trading subsidiary, is a

An engaged work force and -

board member of Homes for Black Children. o Satisfied customers.2: - -.-<-.t "There is an intimate connection between At DTE Energy, we believe the tremendous community service and good business,' says -change within our industry creates endless Bob Buckler, president and chief operating -possibilities for our company to improve, tou ;-

officer of Detroit Edison. ;-innovate,:to grow, to better serve our customers, "We power almost every aspect of your life and ultimaely, to reward our'shareholders.' -: -

and we take this role very seriously:' .We are committed to making that happen. .'- i -

. .X .t r 0 0 *X -_ ' f - .. ,0-4J 17

Standing, from left Gail McGovern, Howard Sims, Frank Hennessey, Allan Gilmour, Josue Robles, Alfred Glancy, and Joe Laymon.

Seated, from left John Lobbia, Lillian Bauder, Tony Earley, Eugene Miller and Charles Pryor.

Anthony F.Earley Jr., 56, has been the chairman and chief executive John E.Lobbia, 64, isthe retired chairman and chief executive officer of DTE Energy since 1998 and was also its president and chief officer of DTE Energy. He retired in 1998. He joined the company in operating officer from 1994to 2004. He joined DTE Energy in 1994 as its 1965 and has served on the DTE Energy Board since 1988. (F,N) president and chief operating officer, the same year he was elected to Gail J. McGovern, 54, has been a professor at Harvard Business the DTE Energy Board.

School since 2002. Prior to that, she was president of Fidelity Lillian Bauder, 66, has been the vice president of Masco Corporation Personal Investments from 1998 to 2002. She was elected to the since January 2005. From 1996 to 2005, she was vice president of DTE Energy Board in2003. (F,P)

Corporate Affairs, Masco Corporation; she was chairman and president of the Masco Corporation Foundation from 2002 until 2005; and served Eugene A. Miller, 68, isthe retired chairman, president and chief as president from 1996 until 2001. She was elected to the DTE Energy executive officer of Comerica Inc. and Comerica Bank. He retired in Board in 1986. (N,A, C) 2002. He joined the DTE Energy Board in 1989. (C,F,0)

Allan D. Gilmour, 71, is the retired vice chairman of Ford Motor Charles W. Pryor Jr., 61, has been the president and chief Company. He served as vice chairman of Ford Motor Company from executive officer of Urenco Inc. since 2003. Prior to that, he was the 1992 to 1995, and then again from 2002 until his retirement in February chief executive officer of Utility Services Business Group of BNFL 2005. He was elected to the DTE Energy Board in 1995. (F,C,0) He was the former chief executive officer of Westinghouse Electric Alfred R.Glancy III, 67, has been the director of Unico Investment Company from 1997 to 2002. Dr. Pryor joined the DTE Energy Board Company since 1974 and its chairman since 2000. He is also the retired in 1999. (F,N) chairman and chief executive officer of MCN Energy Group Inc., Josue Robles Jr., 60, has been the executive vice president, chief serving inthat position from 1988 through 2001. He joined the DTE Energy Board in 2001. (F,P) financial officer and corporate treasurer of the United Services Automobile Association since 1994. Priorto that, he spent 28 years Frank M. Hennessey, 67, has been the chairman and chief executive inthe military, during which he served as the U.S. Army's budget officer of Hennessey Capital LLC since 2002. Prior to that, he was the director at the Pentagon. He was elected to the DTE Energy Board chairman of Emco Limited from 1995 to 2003, and vice chairman and in 2003. (A,P) chief executive officer of MascoTech Inc. from 1998 to 2000. He joined the DTE Energy Board in2001. (A,0) Howard F.Sims, 72, is the chairman and chief executive officer of the Sims Design Group and chairman of SDG Associates LLC and Joe W. Laymon, 53, isthe group vice president, corporate human SDG Design Inc. He had served on the board of MCN Energy since resources and labor affairs, Ford Motor Company since 2003. He was vice president, corporate human resources at Ford from 2001 to 2003, 1988, and joined the DTE Energy Board in2001. (C,N) and executive director, human resources business operation, from 2000 to 2001. Priorto that, he served in other human resources leadership Committeemembership:A-Audit C-CorporateGovernance, roles at Ford, the U.S. State Department Agency for International F-Finance, N-Nuclear Review, O-Organization and Compensation, Development, Kodak Co., and Xerox Corporation. He has served on P-Public Responsibility the DTE Energy Board since 2005. (0) 18

.T, -t-7 7 -om'-.i-taee___-

-~ ~ ~ w~ 1 ~ -; ~ ~ xctv,; Committee k Anthony F.Earley Jr., 56, is chairman and chief Gerard M. Anderson, 47, is president and chief executive officer of DTE Energy. He joined the operating officer (COO). He was named president company in 1994 as president and chief operating in2004 and COO in2005. Previously, he served as officer (COO) and that same year was elected a president of Energy Resources and as executive director. He was elected to his current position vice president of DTE Energy. Anderson joined in 1998. Before joining DTE Energy, Earley served the company in 1993 from McKinsey & Co., where as president and COO of Long Island Lighting he was a consultant in energy and finance.

Company where he had worked since 1985.

Stephen E. Ewing, 61, is vice chairman of Robert J. Buckler, 56, is president and chief it DTE Energy and president and chief operating operating officer of Detroit Edison since 2005.

7r officer of MichCon. He was elected to his Prior to that, he served as group president of I 1 '176 i

current position in 2005, and previously served DTE Energy Distribution. He joined the company as group president of DTE Energy Gas. He in 1974. Buckler has held numerous positions joined the company in2001 from MCN Energy, throughout the organization including power plant where he served as its president and chief engineering, construction and operation, fuel operating officer, and president and chief supply management, transmission and distribution executive officer of its primary subsidiary, operation, customer service, marketing and MichCon. Ewing joined MichCon in 1971. strategic planning.

David E.Meador, 48, is executive vice president Bruce D.Peterson, 49, issenior vice president and chief financial officer (CFO). He joined DTE and general counsel. Prior to joining DTE Energy Energy in 1997 as vice president and controller in2002, he was a partner inthe Washington, and was elected senior vice president and CFO D.C. office of Hunton & Williams, a national law in2001. In2004, he was elected to his current firm specializing in energy industry matters. He position. Inaddition to controller, Meador served spent 14 years with the firm, focusing on energy as senior vice president and treasurer. Prior and infrastructure projectfinance transactions, to joining DTE Energy, he served in a variety of acquisitions and divestitures, and related contract financial and accounting positions at Chrysler structuring and regulatory matters.

Corporation for 14 years, and was an auditor with Coopers & Lybrand.

Lynne Ellyn, 54, is senior vice president and chief Paul C. Hillegonds, 57, is senior vice president information officer. Ellyn joined Detroit Edison of corporate affairs. He joined the company iall in 1998 as vice president and chief information in2005 after serving as president of Detroit 11

't officer after serving as vice president of Business Renaissance since 1997. Prior to that, Hillegonds Applications for Netscape Communications. Ellyn served inthe Michigan House of Representatives has also held senior leadership positions at Xerox from 1979 to 1996. During nearlytwo decades in Corporation and Organic Inc. Earlier inher career the House of Representatives, Hillegonds served she spent nine years with Chrysler Corporation as Republican leader, Co-Speaker of the House, managing advanced technologies. and Speaker of the House.

Ron A. May, 54, is senior vice president of DTE2, Sandra Kay Ennis, 49, is corporate secretary and a multi-year conversion of our ITsystems to SAR chief of staff since 2005. Prior to that, she served He joined the company in 1984 as director of as director of communication planning. She planning and control of nuclear administration. joined the company as a technical writer at the He held a series of increasingly responsible Fermi 2 nuclear power plant in1985 and came to positions, including maintenance superintendent DTE Energy from Bechtel Power Corporation in of Fermi 2; manager of service center operations; Ann Arbor, Mich.

assistant vice president, energy delivery, and vice president energy distribution. May was named to his current position in 2003.

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Chief Financial Officer's Letter terscale and scope..We shed two under-performing busin~esses to focius o-n, three seg-ments where we see the greatest earnings potential: power and industrial projects, unconventional gas production, and fuel transportation and, marketing:We have I

a full pipeline of investment opportunities.,-', -

Iam committed to fundingour growth whileb,-- '.- ,

maintaininga stron'g balance sheet andcash.

flow. We reduced pa'rent 'company debt

.'$120 million in 2005 and plan to continue to' - .. ,.,..I-,

manage the enterprise debt to the appropriate '

level.' We improved our cash flow, and ,

consistently meet our cash flow targets. I I am committed to continue improving our:, -,

credit metrics. My goal is solid investment ggrade ratings from all rating agencies.i I am committed to maintaining an attractive .:'-

dividend yield.: Ourcormpany has paid~a<A-

-,.Ourfinancial healtheimproved dividend every quarter for he pst 96 years al ealh inorvedconsiderab i in2005'and we expecttocontinuethe At 4.8 percent, today it s one of the strongest:,r-momentum in'2006. I'm pleased with yields in the in try. - - i t theAprogress we're making. ' - And, I amcommitted to continued earnings Driving DT nergys success is a proven - growt'o 200 ne inoe a 25perent Ou businessstrategy that positions us well for, above 2004, and we expect an improvement ini2006. However, net income wil increase.

,conrtinued,gro, h,. ,by virtue of exciuding certain non recurring' The financial performance of our two; items, whic

.utilities and the regulatory environment in higher than previous'years.As'we grow, weA it-hich they opertesiginificantlyiniprovedin- '-will;c_ o ely'manage the company's financial 2005.-Planned andmandatedinvestments in, Detroit Edison and MichConImay significantly

'growour asset base byone third, generating additional net income of $145 million fromri

'rsk'nd aintai anenirment fsrong internal controls.

highestpriority. -

Achieving these financial objectives is my ' 1 I 2005to 2010. We will support this investmenti through our broad cost reducti rogram

-'now under way while improving customer tisfaction-

Dvi'd E. Meador -

In addition, we are successfully reinvesting:- Executive Vice President and cash into our non-utility businesses to'grow Chief Financial Officer I------

20

i`_TE Energy Company -

C C .

<'W ni tt Fina>ia'.niio ndRslts fOeain Overview (Dollars inMillions)

Percentage Change from Normal 111 Estimated Effect on Net Income DTE Energy isa growing and diversified energy company with Electric Gas Electric Gas 2005 revenues in excess of $9billion and approximately $23 billion Year Vti1t Utility UWtiiit Utiity Total in assets. Since 2003, our asset base has increased by 12% and 2005 47 % 13) % S 63 $ 14) S 59 operating revenues have grown by 29%. 2004 (171% (4)% $ (40) $ (9) $ 149) 2003 (13) % 2 % $ (24) $ 3 $ (21)

We are the parent company of The Detroit Edison Company (Detroit I1l Electric Utlity isbased on cooling degree days and the Gas Utility isbased on Edison) and Michigan Consolidated Gas Company (MichCon), regulated heating degree days.

electric and gas utilities engaged primarily inthe business of providing electricity and natural gas sales and distribution services throughout The positive impact of warmer weather was partially mitigated by southeastern Michigan. We operate three energy-related non-utility the rate cap on residential customers which prevented us from segments with operations throughout the United States. passing through increased generation and purchased power costs incurred to serve the higher demand. Additionally, we occasionally In2005, our utilities and Power and Industrial Projects segment generated most of our earnings. The improvement in earnings was experience various types of storms that damage our electric due to rate increases at our Michigan utilities, favorable weather distribution infrastructure resulting in power outages. Restoration and continued asset gains from the synthetic fuel business. Earnings and other costs associated with storm-related power outages were also impacted by mark-to-market losses inour Fuel Transportation lowered pretax earnings by $82 million in 2005, $48 million in and Marketing segment and losses from discontinued operations. 2004 and $72 million in 2003.

Our 2005 financial performance improved over 2004. The following Receivables- Both utilities continue to experience high levels of table summarizes our income since 2003: past due receivables, especially within our Gas Utility operations.

(inmillions, except Earnings per Share) 2005 2004 2003 The increase isattributable to economic conditions, high natural gas prices and the lack of adequate levels of assistance for Net Income $ 537 $ 431 $ 521 low-income customers.

Earnings per Diluted Share $ 3.05 $ 2.49 $ 3.09 Excluding Discontinued Operations We have taken aggressive actions to reduce the level of past due and Accounting Changes receivables including, increased customer disconnections, contracting Income from Continuing Operations S 576 $ 461 $ 494 with collection agencies and working with the State of Michigan Earnings per Diluted share S 327 $ 2.66 $ 2.93 and others to increase the share of low-income funding allocated to our customers. In2005, we sold previously written-off accounts The items discussed below influenced our 2005 financial of $187 million resulting in a gain and net proceeds of $6million.

performance and may affect future results: The gain was recorded as arecovery through bad debt expense,

Effects of weather and accounts receivable on utility operations; which isincluded within operation and maintenance expense.

Electric rate orders, electric Customer Choice program, and coal As a result of these factors, our allowance for doubtful accounts and uranium supply; expense for the two utilities decreased to $98 million in2005 from

$105 million in 2004.

Gas rate and gas cost recovery orders and gas supply;

Synfuel-related earnings and the impact of higher oil prices on The April 2005 Michigan Public Service Commission (MPSC) gas production credit phase-outs; rate order provided for an uncollectible tracking mechanism for

Investments in our unconventional gas production business; MichCon. We will file an annual application comparing our actual

Mark-to-market losses in our Fuel Transportation and Marketing uncollectible expense to our designated revenue recovery of business; and approximately $37 million. Ninety percent of the difference from the

Cost reduction efforts and required capital investment. date of the order will be refunded or surcharged after an annual reconciliation proceeding before the MPSC.

Utility Operations Weather- Earnings at our utility operations are seasonal and very Electric Utility sensitive to weather. Electric utility earnings are dependent on hot Electric Rate Orders - In2004, the MPSC issued interim and summer weather, while the gas utility's results are dependent on final rate orders that authorized electric rate increases totaling cold winter weather. The following table explains the impact of $374 million, eliminated transition credits and implemented transition weather relative to 30-year historical normal weather temperatures charges for electric Customer Choice customers. The increases for each utility. were applicable to all customers not subject to a rate cap.

21

The MPSC also authorized the recovery of approximately $385 million Uranium Supply- We operate one nuclear facility that undergoes a in regulatory assets, including stranded costs. As a result of increased periodic refueling outage approximately every eighteen months.

rates, our 2005 pretax margins were higher by $116 million. Uranium prices have been rising due to supply concerns. Inthe future, there may be additional nuclear facilities constructed inthe Electric Customer Choice - Our customers have the option of industry that may place additional pressure on uranium supplies participating in the electric Customer Choice program where they and prices.

can select an alternative electric supplier. Due to distorted pricing mechanisms during the initial period of electric Customer Choice, Gas Utility many commercial customers chose alternative electric suppliers.

The impact of the final rate order in 2004, that increased base Gas Final Rate Order- InApril 2005, the MPSC issued a final rate rates including the recovery of lost margins and transition charges, order authorizing MichCon to earn a rate of return on common combined with recent higher wholesale electric prices has resulted equity of 11 % based on a50% debt and 50% equity capital in many former electric Customer Choice customers migrating back to structure. Highlights of the order include:

Detroit Edison for electrical generation service, partially mitigating

$61 million increase in annual base rates; the financial impact of the electric Customer Choice program.

base rate increase includes $25 million to recover safety and The return of customers from the electric Customer Choice program training costs; resulted in higher gross margins during 2005. The following graph

deferral as a regulatory liability for the non-capitalized portion depicts the electric Customer Choice volumes: of negative pension expense; and

adoption of atracking mechanism for uncollectible accounts Electric Customer Choice Volumes receivable.

inMMh The final rate order from the MPSC denied recovery or required

9,245;.-

accounting impairment for the following items:

g~

$25 million of allocated merger interest from DTE Energy related to the acquisition of MCN Energy; II * $6million of internal labor and legal costs to remediate 2005 2004 2003 manufactured gas plant (MGP) sites;

$5million as a result of a change to the allocation of historical We continue to work with the MPSC to address issues associated MGP insurance proceeds; with the electric Customer Choice program. InFebruary 2005, we * $6million of computer equipment and related depreciation; and filed a revenue-neutral rate restructuring proposal with the MPSC * $42 million impairment related to 90% of the cost of a computer designed to adjust rates for each customer class to be reflective of billing system in place prior to DTE Energy's acquisition of MCN the full costs incurred to service such customers. InDecember 2005, Energy. This impairment had a minimal earnings impact on DTE the MPSC issued an order that took some initial steps to improve Energy because a valuation allowance was established for this the current competitive imbalance in Michigan's electric Customer asset at the time of the MCN acquisition in 2001.

Choice program. The December 2005 order establishes cost-based power supply rates for Detroit Edison's full service customers. Electric Additionally, the rate order adjusted MichCon's depreciation rates Customer Choice participants will pay cost-based distribution and the related revenue requirements with no resulting impact on rates, while Detroit Edison's full service commercial and industrial net income.

customers will pay cost-based distribution rates that reflect the cost of the residential rate subsidy. Residential customers pay a Gas Cost Recovery (GCR) order- Based on rate orders in place for subsidized below cost rate for distribution service. These revenue 2001 and 2002, we filed agas cost recovery case in 2002 and neutral revised rates were effective February 1,2006. recorded a $26 million regulatory asset related to unbilled volumes as of December 31, 2001. Over time we recorded $3million of Coal Supply- Our generating fleet produces in excess of 70% of its interest associated with this regulatory asset. In its April 28, 2005 electricity from coal. Increasing coal demand from domestic and order, the MPSC disallowed recovery and we recorded the impact international markets has resulted in significant price increases. In of the disallowance inthe first quarter of 2005.

addition, difficulty in recruiting workers, obtaining environmental permits and finding economically recoverable amounts of new coal Natural Gas Supply- Increased demand from natural gas power has resulted indecreasing coal output from the central Appalachian plants, 2005 hurricane related supply disruptions, regulatory region. Furthermore, as a result of environmental regulation and constraints and limited exploration have combined to strain existing declining eastern coal stocks, demand for cleaner burning western natural gas supplies and caused substantial increases in prices.

coal has increased. This increased demand for western coal has also resulted in a corresponding demand for western rail shipping, Non-utility Operations straining railroad capacity, resulting inlonger lead times for western coal shipments. We anticipate significant investment opportunities within our non-utility businesses. We employ disciplined investment criteria 22

when assessing opportunities that will leverage our existing assets, The value of a production tax credit can vary each year and is skill and expertise. Specifically, we invest intargeted energy markets adjusted annually by an inflation factor as published by the Internal with attractive competitive dynamics where meaningful scale is in Revenue Service (IRS) in April of the following year. The value of alignment with our risk profile. Assuming no phase-out of production the production tax credit ina given year isreduced if the Reference tax credits, the source of investment capital isthe estimated Price of oil within the year exceeds a threshold price and is cumulative $1.2 billion we anticipate from synfuel cash flow which eliminated entirely if the Reference Price exceeds a phase-out price.

consists of cash from operations, asset sales, and the utilization of The Reference Price of a barrel of oil isan estimate of the annual current and previously earned production tax credits to reduce tax average wellhead price per barrel for domestic crude oil. During payments. Tax credit carryforward utilization inpart could be extended 2005, the monthly average wellhead prices were approximately past 2008, if taxable income isreduced from current forecasts. $6lower than the New York Mercantile Exchange (NYMEX) price However, if oil prices remain at current levels or continue to for light, sweet crude oil. The actual or estimated Reference Price increase, the estimated cash flow from the synfuel business would and beginning and ending phase-out prices per barrel of oil for be significantly less and would adversely impact the success of 2004 through 2007 are as follows:

this strategy, unless we identify alternative sources of cash.

Reference Beginning Ending Price Phase-Out Price Phase-Out Price Power and Industrial Projects 2004 (actual) $36.75 $51.35 $6446 We anticipate building around our core strengths inthe markets 2005 (estimated) $51 $53 $66 where we operate. Indetermining the markets in which to compete, 2006 (estimated) Not Available $53 $67 we closely examine the regulatory environment, the number of 2007 lestimated) Not Available $54 $68 competitors and our ability to achieve sustainable margins. We plan to maximize the effectiveness of our inter-related businesses as we expand from our current regional focus. As we pursue Recent events have increased domestic crude oil prices, including growth opportunities, our first priority will be to achieve value- hurricane-related supply disruptions and continued worldwide added returns. demand. Through December 31, 2005, the NYMEX daily closing price of a barrel of oil for 2005 averaged approximately $57, We plan to focus on the following areas for growth: which due to the uncertainty of the wellhead/NYMEX difference, iscomparable to an approximate $51 Reference Price. For the

Optimizing the remaining life of our synfuel portfolio; remaining life of the tax credits, if the Reference Price falls within

Providing operating services to owners of industrial and power or exceeds the phase-out range, the availability of production tax plants; credits inthat year would be reduced or eliminated. Any actual tax credit phase-out for 2006 and available tax credits, if any, will not

Acquiring and developing solid fuel-fired power plants; be certain until published by the IRS in April 2007. As of February

Expanding on-site energy projects; and 28, 2006, the realized and unrealized NYMEX daily closing price of

Developing new tax advantaged opportunities. a barrel of oil was $65.08, equating to an estimated Reference Price of $59, which is within the phase-out range. If prices remain Synfuel-related Eamings - We operate nine synthetic fuel production at this level throughout 2006, we would experience a phase-out of plants throughout the United States. Synfuel plants chemically the production tax credits and our synthetic fuel business would be change coal into a synthetic fuel as determined under the Internal adversely affected; this could have an impact on our synthetic fuel Revenue Code. Production tax credits are provided for the production production plans which, inturn, may have a material adverse impact and sale of solid synthetic fuel produced from coal. These tax credits on our results of operations, cash flow, and financial condition.

expire on December 31, 2007. Our synthetic fuel plants generate However, we cannot predict with any certainty the Reference Price operating losses which are offset by the resulting production tax for 2006 or beyond.

credits. We have not had sufficient taxable income to fully utilize production tax credits earned in prior periods. As of December 31, There is legislation pending in Congress that may impact the 2005, we have $484 million intax credit carry-forwards. potential phase-out of production tax credits for 2006 and 2007.

The legislation would use the prior year oil price to determine the To optimize income and cash flow from our synfuel operations, we current year Reference Price. We are unable to predict the outcome have sold interests in all nine of our facilities, representing 91% of of this legislation.

our total production capacity as of December 31, 2005. We will continue to evaluate opportunities to sell additional interests in The gain from the sale of synfuel facilities iscomprised of fixed our two remaining majority-owned plants. Proceeds from the sales and variable components. The fixed component represents note are contingent upon production levels and the value of such credits. payments of principal and interest, isnot subject to refund, and is When we sell an interest in a synfuel project, we recognize the recognized as a gain when earned and collectibility isassured. The gain as the facility produces and sells synfuel and when there is variable component isbased on an estimate of tax credits allocated persuasive evidence that the sales proceeds have become fixed or to our partners, is subject to refund based on the annual oil price determinable and collectibility is reasonably assured. Insubstance, phase-out, and is recognized as a gain only when the probability of we are receiving synfuel gains and reduced operating losses in refund isconsidered remote and collectibility isassured. Additionally, exchange for tax credits associated with the projects sold. Sales based on estimates of tax credits allocated, our partners reimburse of interests in synfuel projects allow us to accelerate cash flow us (through the project entity) for the operating losses of the synfuel while maintaining a stable income base.

23

facilities. Inthe event that the tax credit isphased out, we are Unconventional Gas Production contractually obligated to refund to our partners all or a portion During the past year, natural gas prices have reached historically of the operating losses funded by our partners. To assess the high levels. These high prices provide attractive opportunities for probability of refund, we use valuation and analysis models that our Unconventional Gas Production business segment. We are an calculate the probability of surpassing the estimated lower band experienced operator with 15 years of experience in the Antrim of the phase-out range for the Reference Price of oil for the year. shale in northern Michigan, and we recently expanded our operations Due to the rise in oil prices, there was a possibility that the 2005 in the Barnett shale basin in north central Texas. Recent leasehold Reference Price of oil could have reached the threshold at which acquisitions have increased our total leasehold acreage to 452,621 production tax credits would have begun to phase-out. We deferred acres (366,693 net of interest of others). Over the next few years, all variable gains for the first three quarters of 2005. However, in our goal isto expand our existing leasehold acreage position and the fourth quarter of 2005, when there was persuasive evidence transform unproved acreage into proved reserves.

that the Reference Price of oil would not surpass the estimated lower band of the phase-out range, we recognized all the variable Antrim Shale - We plan to grow through the extension of existing gains related to 2005, of which $167 million (pre-tax) were producing areas and acquisition of other producer's properties.

attributable to the first three quarters of 2005. Additionally, we intend to develop existing acreage using the latest horizontal drilling techniques and to continue to search for Due to changes in the agreements with certain of our synfuel expansion acreage. Some of our long-term fixed-price obligations partners and the exercise of existing rights by other of our synfuels for production of Antrim gas begin to expire in 2006. This will partners, a higher percentage of the expected payments in 2006 create opportunities to remarket Antrim production at significantly may be variable note payments. As a result, a larger portion of the higher current market rates.

2006 synfuel payments may be subject to refund should a phase-out occur. We will likely defer recognition of the quarterly variable 2005 2004 2003 and certain indemnified fixed note payments in 2006 until the Michigan - Antrim Shale probability of refund isremote and collectibility is assured. Net Producing Wells 1,630 1,523 1,471 Production Volume (Bcfe) 21.5 2Z5 23.2 As discussed in Note 12, we have entered into derivative and other Proved Reserves IlBcfe) 338.4 335.4 351.9 contracts to economically hedge aportion of our 2006 and 2007 Net Developed Acreage 217,643 213,959 212,067 synfuel cash flow exposure related to the risk of oil prices increasing. Net Undeveloped Acreage 73,056 79,025 81,133 The derivative contracts are marked to market with changes in fair Capital Expenditures (inmillions) $ 37 $ 22 $ 26 value recorded as an adjustment to synfuel gains. We recorded a $ 760 $ 485 Future Net Cash Flows (inmillions)(11) $ 1,307 pretax mark to market gain of $48 million during 2005. As part of $ 3.10 $ 2.97 Average gas pricewith hedges (per Mcfl $ 3.10 our synfuel-related risk management strategy, we continue to Average gas price without hedges evaluate alternatives available to mitigate unhedged exposure to (per Mcf) (2) S 7.73 $ 5.57 $ 4.98 oil price volatility. These contracts, and other actions we can take. Represents the standardized measure of discounted future net cash flows as calculated (11) and have taken, will protect approximately 53% of our 2006 cash by an independent engineering firm utilizing extensive estimates. The estimated future flow and 31 %of our 2007 cash flow. As our risk management net cash flow computations should not be considered to represent our estimate of the expected revenues or the current value of existing proved reserves and do not include position changes due to market volatility or legislative actions, we the impact of hedge contracts.

may adjust our hedging strategy in response to changing conditions. 12iThe gas produced in the Antrim shale issubject to hedges that begin to expire in 2006.

In2006, we expect to remarket 2.0 Bcf at current market pricing. For 2007, we antici-Inaddition to entering into economic hedges, we can mitigate our pate remarketing an additional 1.8Bcf.

exposure to a tax credit phase-out by shutting down or reducing Bamett Shale -We anticipate significant opportunities in our existing production at our synfuel facilities, which decreases the amount of Barnett shale acreage and expect continued extension of producing operating losses we generate. We regularly monitor oil prices and areas within the Fort Worth Basin. We are currently inthe test and have created contingency plans to cease synfuel production. development phase for unproved and recently acquired Barnett shale acreage. We plan to increase our acreage through small Assuming no synfuel tax credit phase-out, we expect cash flow negotiated acquisitions to build scale.

from our synfuel business will be approximately $1.2 billion from 2006 to 2008. Ifprices remain at current levels or increase throughout 2006, synfuel production levels may be reduced, which would reduce the income and cash flow from this business. Ifthe Reference Price results in a complete phase out of the synfuel tax credits for 2006, and assuming the previously discussed current level of economic hedges and an early cessation of synfuel production to avoid operating losses, there is a potential negative impact to net income and cash flow of $160 million and $140 million, respectively, before any potential asset impairment and goodwill write-off.

24

2005 2004 2003 produce the timing related earnings swings from period to period.

Texas - Barnett Shale We expect the timing difference on the forward power contracts Net Producing Wells 55 1 - will not be fully realized until 2007.

Production Volume (Bcfe) 0.7 - -

Proved Reserves (Bcfe) 58.6 7.9 - Operating System and Performance Net Developed Acreage 14,637 316 - Excellence Process NetUndevelopedAcreage 61,627 48,541 3,156 Capital Expenditures (inmillions) S 107 $ 16 $ 2 We continuously review and adjust our cost structure and seek improvements in our processes. Beginning in 2002, we adopted Future Net Cash Flows (inmillions) (1) S 127 $ 7 -

the DTE Energy Operating System, which isthe application of tools Average gas price (per Mcf) S 9.01 S 5.70 (11Represents the standardized measure of discounted future net cash flows as calculated and operating practices that have resulted inoperating efficiencies, by an independent engineering firm utilizing extensive estimates. The estimated future inventory reductions and improvements intechnology systems, net cash flow computations should not be considered to represent our estimate of the among other enhancements. Some of these cost reductions may expected revenues or the current value of existing proved reserves and do not include be returned to our customers inthe form of lower Power Supply the impact of hedge contracts.

Cost Recovery (PSCR) charges and the remaining amounts may Due to high natural gas prices and the potential for successes impact our profitability.

within the Barnett shale, more capital is being invested into the region. The competition for opportunities and goods and services As an extension of this effort, in mid-2005, we initiated acompany-may result in increased operating costs. However, our experience wide review of our operations called the Performance Excellence in the Antrim shale and our experienced Barnett shale personnel Process. The overarching goal has been and remains to become provide an advantage inaddressing potential cost increases. We more competitive by reducing costs, eliminating waste and expect to invest a combined amount of approximately $100 million optimizing business processes while improving customer service.

to $130 million inour unconventional gas business in 2006. Many of our customers are under intense economic pressure and will benefit from our efforts to keep down our costs and their Fuel Transportation and Marketing rates. Additionally, we will need significant resources in the future to invest inthe infrastructure necessary to compete. Specifically, Pipelines, Processing and Storage is inthe process of expanding we began a series of focused improvement initiatives within our our storage capacity in Michigan and expanding and building new Electric and Gas Utilities, and our corporate support function.

pipeline capacity to the northeast United States. Our Coal Transportation and Marketing business will seek to build our The process will be rigorous and challenging and seeks to yield capacity to transport greater amounts of western coal and may sustainable performance to our customers and shareholders. We seek to expand into coal terminals. have identified the Performance Excellence Process as critical to our long-term growth strategy. We are entering the implementation Significant portions of the electric and gas marketing and trading phase and expect to begin to realize the benefits from the effort in portfolio are economically hedged. The portfolio includes financial 2006. The cost to execute the Performance Excellence Process instruments and gas inventory, as well as owned and contracted could result in non-recurring restructuring charges in2006.

natural gas pipelines and storage capacity positions. Most financial instruments are deemed derivatives, whereas the gas inventory, pipelines and storage assets are not derivatives. As a Capital Investment result, this segment may experience dramatic earnings volatility as We anticipate significant capital investment across all of our derivatives are marked to market without revaluing the underlying business segments. Most of our capital expenditures will be non-derivative contracts and assets. This results in gains and concentrated within our utility segments. Our electric utility losses that are recognized in different accounting periods. We currently expects to invest approximately $4billion due to incur gains or losses in one period that are subsequently reversed increased environmental requirements and reliability enhancement when transactions are settled. projects through 2010. Our gas utility currently expects to invest approximately $900 million on system expansion, pipeline safety During 2005, our earnings were negatively impacted by the and reliability enhancement projects through the same period.

economically favorable decision in early 2005 to delay previously We plan to seek regulatory approval to include these capital planned withdrawals from gas storage due to a decrease in the expenditures within our regulatory rate base.

current price for natural gas and an increase inthe forward price for natural gas. The financial impact of this timing difference has During 2005, we began the first wave of implementation of DTE2, begun to reverse as the gas is withdrawn from storage in the an enterprise resource planning system initiative to improve existing current storage cycle and is sold at prices significantly in excess processes and to implement new core information systems. We of the cost of gas in storage. Inaddition, we entered into forward anticipate spending $165 million to $190 million over the next two power contracts to economically hedge certain physical and capacity years as the remaining system elements are developed and business power contracts. Some of these underlying contracts are not segments fully adopt DTE2.

derivatives, while the related economic hedges are derivatives, and therefore marked to market. As a result, these transactions Inthe future, we may build a new base-load electric generating plant. The last base load plant constructed within our electric utility 25

service territory was approximately twenty years ago. A recently the adoption of a new accounting rule in 2005 and two new completed study, sponsored by the MPSC, projected that Michigan accounting rules in2003. Excluding discontinued operations and may need to install 7,000 megawatts (MW) of additional capacity the cumulative effect of accounting changes, our income from con-over the next ten years. We estimate that a new base-load plant tinuing operations in2005 was $576 million, or $3.27 per diluted will cost between $1billion and $2billion. share, compared to income of $461 million, or $2.66 per diluted share in 2004 and income of $494 million, or $2.93 per diluted Outlook share in2003. The following sections provide a detailed discussion of our segments, operating performance and future outlook.

The next few years will be a time of rapid change for DTE Energy and for the energy industry. Our strong utility base combined with (inMillions, exceptper share data) 2005 2004 2003 our integrated non-utility operations position us well for long-term Net Income (Loss) growth. Due to the enactment of the Energy Policy Act of 2005 Electric Utility $ 277 S 150 $ 252 and the repeal of the Public Utility Holding Company Act of Gas Utility 37 20 29 1935 there are fewer barriers to mergers and acquisitions of Non-utility Operations:

utility companies. We anticipate greater industry consolidation Power and Industrial Projects 308 179 197 over the next few years resulting in the creation of large regional Unconventional Gas Production 4 6 12 utility providers. Fuel Transportation and Marketing 2 118 69 Corporate & Other (52) (12) (65)

Looking forward, we will focus on several points that we expect Income (Loss) from Continuing Operations:

will improve future performance: Utility 314 170 281 Non-utility 314 303 278

continuing to pursue regulatory stability and investment recovery Corporate & Other (52) (12) (65) for our utilities; 576 461 494

managing the growth of our utility asset base; Discontinued Operations (36) (301 54

enhancing our cost structure across all business segments; Cumulative Effect of Accounting Changes (3) - (27)

improving our Electric and Gas Utility customer satisfaction; Net Income S 537 $ 431 $ 521

increasing the scale in our three non-utility business segments; and Diluted Earnings Per Share

investing inbusinesses that integrate our assets and leverage Total Utility S 1.78 $ .98 $ 1.67 our skills and expertise. Non-utility Operations 1.78 1.75 1.65 Corporate & Other (.29) (.07) (.39)

Along with pursuing aleaner organization, we expect to receive an Income from Continuing Operations 3.27 2.66 2.93 estimated $1.2 billion (assuming no phase-out) of synfuel cash Discontinued Operations (.20) (.17) .32 flow through 2008, which consists of cash from operations, asset Cumulative Effect of Accounting Changes (.02) - (.16) sales, and the utilization of production tax credits to reduce tax Net Income S 3.05 $ 2.49 $ 3.09 payments. Tax credit utilization in part could be extended past 2008, if taxable income isreduced from current forecasts. However, if oil prices remain at current levels or continue to increase, the The earnings per share of any segment does not represent a direct estimated cash flow from the synfuel business would, as a result legal interest inthe assets and liabilities allocated to any one of production tax credit phase-out, be significantly less and would segment but rather represents a direct or indirect equity interest in adversely impact the success of this strategy, unless we identify DTE Energy's assets and liabilities as awhole.

alternative sources of cash.

Electric Utility Anticipated redeployment of this expected available cash will reduce DTE Energy's debt and replace the value of synfuel operations Our Electric Utility segment consists of Detroit Edison, which inherent in our share price by pursuing investments in targeted isengaged in the generation, purchase, distribution and sale energy markets. If adequate investment opportunities are not of electricity to approximately 2.2 million customers in available, share repurchases may be used to build shareholder southeastern Michigan.

value. We remain committed to a strong balance sheet and financial coverage ratios, and paying an attractive dividend. Factors impacting income: Our net income increased $127 million to $277 million in 2005 from $150 million in 2004. 2004 net income decreased $102 million from $252 million in 2003. These results Results of Operations primarily reflect higher rates due to the November 2004 MPSC final rate order, return of customers from the electric Customer Net income in 2005 was $537 million, or $3.05 per diluted share, Choice program, warmer weather and lower operations and compared to net income of $431 million, or $2.49 per diluted share maintenance expenses in 2005, partially offset by a portion of in2004 and net income of $521 million, or $3.09 per diluted share in higher fuel and purchased power costs, which were unrecoverable 2003. The comparability of earnings was impacted by our discontinued as a result of residential rate caps (which expired January 1,2006),

businesses, DTE Energy Technologies (Otech), Southern Missouri and increased depreciation and amortization expenses.

Gas Company and International Transmission Company (ITC), and 26

(in Millions) 2005 2004 2003 previously recorded inoperation and maintenance expenses Operating Revenues $ 4,462 $ 3,568 $ 3,695 in 2004, isnow reflected in purchased power expenses. The Fuel and Purchased Power 1,590 885 939 PSCR mechanism provides related revenues for the transmission Gross Margin Z872 2,683 2,756 expense.

Operation and Maintenance 1,308 1,395 1,332 Depreciation and Amortization 640 523 473 The decline in2004 revenues was partially offset by increased Taxes OtherThan Income 241 249 257 base rates resulting from the interim and final rate orders.

Asset (Gains) and Losses, Net (26) (1) 20 Revenues in2004 were adversely impacted by reduced cooling Operating Income 709 517 674 demand resulting from mild summer weather. Inaddition, operating revenues and fuel and purchased power costs decreased in 2004 Other (Income) and Deductions 283 303 277 reflecting a $1.27 per MWh (8%) decline in fuel and purchased Income Tax Provision 149 64 145 power costs. The loss of retail sales under the electric Customer Net Income $ 277 $ 150 $ 252 Choice program also resulted in lower purchase power require-Operating Income as a Percent of ments, as well as excess power capacity that was sold inthe Operating Revenues 16% 14% 18%

wholesale market. Under the 2004 interim and final rate orders, revenues from selling excess power reduce the level of recover-Gross margins increased $189 million during 2005 and declined able fuel and purchased power costs and, therefore, do not impact

$73 million in 2004. Operating revenues increased due to higher margins associated with uncapped customers.

demand resulting from warmer weather in 2005 and increased rates due to the November 2004 MPSC final rate order, partially The rate orders also lowered PSCR revenues, which were partially offset by unrecovered power supply costs as a result of residential offset by increased base rate and transition charge revenues.

rate caps (which expired January 1,2006) and a poor Michigan Since fuel and purchased power costs are a pass-through with economy in 2005. Gross margins were favorably impacted by the reinstatement of the PSCR in 2004, adecrease affects both decreased electric Customer Choice penetration, whereby Detroit revenues and fuel and purchased power costs but does not affect Edison lost 12% of retail sales to electric Customer Choice customers margins or earnings associated with uncapped customers. The in 2005 and 18% of such sales during 2004 as retail customers decrease infuel and purchased power costs isattributable to migrated back to Detroit Edison as their electric generation provider lower priced purchases and the use of a more favorable power rather than remaining with alternative suppliers. The following supply mix driven by higher generation output. The favorable mix table displays changes invarious gross margin components isdue to lower purchases, driven by lost sales under the electric relative to the comparable prior period: Customer Choice program.

(inMillions) 2005 2004 (inThousands of MWh) 2005 2004 2003 Increase (Decrease) inGross Margin Power Generated and Purchased Components Compared to Prior Year Power Plant Generation Weather related margin S 166 $ (25) Fossil 40,756 73 % 39,432 75 % 38,052 72 %

MPSC 2004 rate orders 116 22 Nuclear 8,754 16 8,440 16 8,114 16 Unrecovered power supply 49,510 89 47,872 91 46,166 88 costs - residential customers (73) -

Purchased Power 6,378 11 4,650 9 6,354 12 Transmission charges (1) (93) -

System Output 55,888 10 % 52522 100% 52,520 100%

Electric Customer Choice program 79 (82)

Less Line Loss and Internal use (3,205) (3,574) 13,248)

Service territory economic performance (23) 9 48,948 49,272 Net System Output 52,583 Other, net 17 3 Average Unit Cost ($/MWh)

Increase (decrease) in gross margin $ 189 $ (73) Generation (1) S 15.47 $12.98 $12.89 I1)Transmission expenses were recorded inoperation and maintenance expense in23004.

Purchased Power S 89.37 $37.06 $41.73 Overall Average Unit Cost S 23.90 $15.11 $16.38 Operating revenues and fuel and purchased power costs increased (11)

Represents fuel costs associated with power plants.

in 2005 reflecting a $8.79 per megawatthour of electricity (MWh)

(58%) increase in fuel and purchased power costs during the year.

Fuel and purchased power costs are a pass-through with the reinstatement of the PSCR mechanism, except for residential customers whose rate caps expired in January 2006.

The increase in power supply costs was driven by higher seasonal demand, higher purchased power rates, higher coal prices and increased power purchases due to weather and plant outages.

Pursuant to the MPSC final rate order, transmission expense, 27

(inThousands of MMVVI) 2005 2004 2003 Asset (gains) and losses, net increased $25 million in 2005 as a Electric Sales result of our sale of land near our headquarters.

Residential 16,812 15,081 15,074 Commercial 15,618 13,425 15,942 Other income and deductions expense decreased $20 million in Industrial 12,317 11,472 12,254 2005 and increased $26 million in 2004. The 2005 decrease isdue Wholesale 2,329 2,197 2,241 primarily to lower interest expense as a result of lower interest 401 402 rates and afavorable adjustment related to tax audit settlements.

Other 390 42,576 45,913 The 2004 increase is primarily due to lower income associated 47,466 5,217 6,372 3,359 with recording a return on regulatory assets, as well as costs Interconnectionsales(1) associated with addressing the structural issues of PA 141.

Total Electric Sales 52683 48,948 49,272 Electric Deliveries Outlook - We continue to improve the operating performance of Retail and Wholesale 47,466 42,576 45,913 Detroit Edison. During the past year we have resolved many of our Electric Choice 6,760 9,245 6,193 regulatory issues and continue to pursue additional regulatory Electric Choice - Self Generators (2) 518 595 1,088 solutions for structural problems within our competitive environment, Total Electric Sales and Deliveries 54,744 52,416 53,194 mainly electric Customer Choice and the need to adjust rates for 1)Represents power that isnot distributed by Detroit Edison. each customer class to reflect the full cost of service.

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

Concurrently, we will move forward in our efforts to improve Operation and maintenance expense decreased $87 million in performance. Looking forward, additional issues, such as rising 2005 and increased $63 million in2004. As a result of the MPSC prices for coal, uranium and health care, continued under-performance final rate order, transmission and Midwest Independent System of Michigan's economy and capital spending, will result in us Operator (MISO) expenses in 2005 are now included in purchased taking meaningful action to address our costs while continuing to power expense with related revenues recorded through the PSCR provide quality customer service. We will utilize the DTE Operating mechanism. Inaddition, as a result of the MPSC final rate order, System and the Performance Excellence Process to seek opportunities merger interest isno longer allocated from the DTE Energy parent to improve productivity, remove waste, decrease our costs, while company to Detroit Edison. Partially offsetting the lack of merger improving customer satisfaction.

interest expense and the transmission expense accounting reclassification were higher 2005 storm expenses. Long term, we will be required to invest an estimated $2.4 billion on emission controls through 2018. Should we be able to recover The 2004 increase reflects costs associated with maintaining our these costs in future rate cases, we may experience a growth in generation fleet, including costs of scheduled and forced plant earnings. Additionally, our service territory may require additional outages. Additionally, the increase in 2004 isdue to incremental generation capacity. A new base-load generating plant has not costs associated with the implementation of our DTE2 project. been built within the State of Michigan inthe last 20 years. Should our regulatory environment be conducive to such a significant capital Storm Restoration Costs expenditure, we may build or expand anew base- load facility, (inmillions) with an estimated cost of $1billion to $2billion.

The following variables, either in combination or acting alone, will impact our future results:

amount and timing of cost recovery allowed as a result of regulatory proceedings, related appeals, or new legislation;

our ability to reduce costs; Operation and maintenance expense in both years includes higher

variations in market prices of power, coal and gas; employee pension and health care benefit costs due to financial

plant performance; market performance, discount rates and health care cost trend

economic conditions within the state of Michigan; rates, and increased reserves for uncollectible accounts receivable,

weather, including the severity and frequency of storms; and reflecting high past-due amounts attributable to economic conditions.

levels of customer participation inthe electric Customer Inaddition, we accrued a refund due from the Midwest Independent Choice program.

System Operator in 2004 for transmission services.

We expect cash flows and operating performance will continue to Depreciation andamortization expense increased $117 million in2005 be at risk due to the electric Customer Choice program until the and increased $50 million in 2004. The increases reflect the income issues associated with this program are adequately addressed. We effect of recording regulatory assets, which lowered depreciation and will accrue as regulatory assets any future unrecovered generation-amortization expenses. The regulatory asset deferrals totaled $46 million related fixed costs (stranded costs) due to electric Customer in 2005, $107 million in 2004 and $153 million in2003, representing Choice that we believe are recoverable under Michigan legislation net stranded costs and other costs we believe are recoverable under and MPSC orders. We cannot predict the outcome of these matters.

Public Act (PA) 141. Additionally, higher 2005 sales volumes compared See Note 4.

to 2004 resulted in greater amortization of regulatory assets.

28

Gas Utility 2005 2004 2003 Gas Markets (inMillions)

Our Gas Utility segment consists of MichCon and Citizens Fuel Gas Gas sales $ 1,860 S 1,435 $ 1,242 Company (Citizens), natural gas utilities subject to regulation by the End user transportation 134 119 136 MPSC. MichCon isengaged inthe purchase, storage, transmission, 1,994 1,554 1,378 distribution and sale of natural gas to approximately 1.3 million Intermediate transportation 58 56 51 residential, commercial and industrial customers in the State of Other 86 72 69 Michigan. MichCon also has subsidiaries involved in the gathering S 2138 $ 1,682 $ 1,498 and transmission of natural gas in northern Michigan. MichCon operates one of the largest natural gas distribution and transmission Gas Markets (inBcf)

Gas sales 168 173 181 systems inthe United States. Citizens distributes natural gas in End usertransportation 157 145 152 Adrian, Michigan.

325 318 333 Factors impacting income: Gas Utility's net income increased $17 Intermediate transportation 432 536 576 million in2005 and declined $9million in 2004, compared to the 757 854 909 prior year, primarily reflecting the impact of the MPSC's April 2005 gas cost recovery and final rate orders. Operation and maintenance expense increased $21 million in 2005 and $32 million in2004. The 2005 increase is primarily due to the The MPSC final gas rate order disallowed recovery of 90% of the impact of the MPSC rate order that disallowed certain environmental costs of a computer billing system that was in place prior to DTE expenses that had been recorded as a regulatory asset and its Energy's acquisition of MCN Energy in 2001. MichCon impaired requirement to defer negative pension expense as a regulatory this asset by approximately $42 million inthe first quarter of 2005. liability. For 2005, uncollectible accounts receivables expense This disallowance was not reflected at the DTE Energy level since remained consistent with 2004, reflecting higher past due amounts this impairment was previously reserved at the time of the MCN attributable to an increase in gas prices, continued weak economic acquisition in 2001. conditions and inadequate government-sponsored assistance for low-income customers. The 2005 final rate order provided revenue (inMillions) 2005 2004 2003 for an uncollectible expense tracking mechanism to mitigate some Operating Revenues $ 2138 $ 1,682 $ 1,498 of the effect of increasing uncollectible expense. The increase in Cost of Gas 1,490 1,071 909 operation and maintenance expense was partially offset by the Gross Margins 648 611 589 DTE Energy parent company no longer allocating merger-related Operation and Maintenance 424 403 371 interest to MichCon effective in April 2005, as a result of the Depreciation and Amortization 95 103 101 disallowance of those costs inthe April 2005 final rate order.

Taxes Other Than Income 43 49 52 The increase was also partially offset by a decline in accruals for Asset (Gains) and Losses, Net 4 (3) - injuries and damages during 2005.

Operating Income 82 59 65 Other (Income) and Deductions 47 48 36 The 2004 period reflects higher reserves for uncollectible Income Tax Benefit (2) (9) -

accounts receivable and pension and health care costs. The Net Income $ 37 $ 20 $ 29 increase in uncollectible accounts expense reflects high past Operating Income as a Percent due amounts attributable to an increase ingas prices, continued of Operating Revenues 4 % 4 % 4% weak economic conditions and alack of adequate public assistance for low-income customers.

Gross margins increased $37 million in 2005 and increased $22 Uncollectible Accounts Expense million in 2004, compared to the prior year. Gross margins in2005 (inmillions) were favorably affected by higher base rates as a result of the $~~60`,

interim and final gas rate orders, and revenue associated with the uncollectible expense tracking mechanism authorized by the MPSC.

InApril 2005, the MPSC issued an order inthe 2002 GCR reconciliation case that disallowed $26 million representing unbilled revenues at a,1W December 2001. We recorded the impact of the disallowance during mmml - a-the first quarter of 2005. Operating revenues and cost of gas increased 2005 2004 2003 in 2005 reflecting higher gas prices which are recoverable from Asset (gains) and losses; net declined $7 million in2005 as a customers through the GCR mechanism. The 2004 gross margin result of a write-off of certain computer equipment and related comparison was also affected by a $26.5 million pre-tax reserve depreciation resulting from the April 2005 final rate order.

recorded in 2003 for the potential disallowance in gas costs pursuant to an MPSC order in MichCon's 2002 GCR plan case. See Note 4. Income taxes increased by $7million in 2005 and decreased by

$9million in 2004 due to variations in pre-tax earnings.

29

Outlook- Operating results are expected to vary as a result of factors Operating revenues increased $256 million in 2005 and $162 million such as regulatory proceedings, weather, changes in economic in 2004 primarily reflecting higher synfuel sales due to increased conditions, cost containment efforts and process improvements. production, and higher market prices for our coke production.

Higher gas prices and economic conditions have resulted in Operating expenses associated with synfuel projects exceed operating continued pressure on receivables and working capital requirements revenues and therefore generate operating losses, which have been partially mitigated by the GCR mechanism. We believe our more than offset by the resulting production tax credits. When we allowance for doubtful accounts is based on reasonable estimates. sell an interest ina synfuel project, we recognize the gain from In the April 2005 final gas rate order, the MPSC adopted MichCon's such sale as the facility produces and sells synfuel and when there proposed tracking mechanism for uncollectible accounts receivable. is persuasive evidence that the sales proceeds have become fixed Each year, MichCon will file an application comparing its actual or determinable and collectibility is reasonably assured.

uncollectible expense for the prior calendar year to its designated revenue recovery of approximately $37 million. Ninety percent of The improvement in 2004 synfuel revenues results from increased the difference will be refunded or surcharged after an annual production due to additional sales of project interests in 2004, reconciliation proceeding before the MPSC. reflecting our strategy to produce synfuel primarily from plants in which we had sold interests inorder to optimize income and cash flow.

Non-utility Operations Synfuel Earnings (inmillions)

Power and Industrial Projects Power and Industrial Projects is comprised of Coal-Based Fuels, $198 $197 On-Site Energy Projects, Non-Utility Power Generation, Landfill Gas E Gains on Synfuel Sales, including interest Recovery and Waste Coal Recovery. Coal-Based Fuels operations include producing synthetic fuel from nine synfuel plants and MProduction Tax Credits producing coke from two coke battery plants. The production of 3Operating Losses, net of synthetic fuel from all of our synfuel plants and the production of Wu inority Interest coke from one of our coke batteries generate production tax credits.

On-Site Energy Projects include pulverized coal injection, power generation, steam production, chilled water production, wastewater treatment and compressed air supply. Non-Utility Power Generation 2005 2004 2003 owns and operates four gas-fired peaking electric generating Revenues from on-site energy projects increased in2005, reflecting plants and manages and operates one additional gas-fired power the addition of new facilities, completion of new long-term utility plant under contract. Landfill Gas Recovery develops, owns and services contracts with a large automotive company and a large operates landfill recovery systems throughout the United States. manufacturer of paper products. Revenues in2004 include a $9million Waste Coal Recovery uses proprietary technology to produce high pre-tax fee generated inconjunction with the development of a related quality coal products from fine coal slurries typically discarded energy project, 50% of which was sold to an unaffiliated partner.

from coal mining operations.

Operation and maintenance expense increased $281 million in Factors impacting income: Netincome increased $129 million in 2005 and $108 million in2004, reflecting costs associated with 2005 and decreased $18 million in 2004, compared to 2003. These increased synfuel production, 2005 acquisitions of three on-site results primarily reflect higher gains recognized from selling interests energy projects and coke operations. Partially offsetting 2004 higher in our synfuel plants, gains and losses on synfuel hedges, and synfuel operating costs was the recording of insurance proceeds varying levels of production tax credits. associated with an accident at one of our coke batteries.

(inMillions) 2005 2004 2003 Asset (gains) and losses, net increased $153 million in 2005 and Operating Revenues $ 1,356 $ 1,100 $ 938 $101 million in2004. The improvements are due to increased Operation and Maintenance 1,497 1,216 1,108 production and sales volume from our synfuel projects. To Depreciation and Amortization 107 89 90 economically hedge our exposure to the risk of an increase inoil Taxes other than Income 34 16 18 prices that could reduce synfuel sales proceeds, we entered into Asset (Gains) and Losses, Net (368) (215) (114) derivative and other contracts. The derivative contracts are marked Operating Income (Loss) 86 (6) (164) to market with changes in their fair value recorded as an adjustment Other (Income) and Deductions (30) (15) 1 to synfuel gains. We recorded 2005 synfuel hedge mark to market Minority Interest (281) (212) (91) gains of $48 million, compared to 2004 mark to market losses of Income Taxes $12 million. See Note 12.

Provision (Benefit) 144 80 (30)

Production Tax Credits (55) (38) (241) Minority interestincreased $69 million in2005 and $121 million in 89 42 (271) 2004, reflecting our partners' share of operating losses associated Net Income $ 308 $ 179 $ 197 with synfuel operations. The sale of interests in our synfuel facilities during prior periods resulted inallocating a larger percentage of such losses to our partners.

3(

Income taxes increased $47 million in2005 and $313 million in Other (income) and deductions decreased $2million in2005 and 2004. The increase in2005 reflects higher taxable earnings, increased $3million in 2004. Interest expense was the primary partially offset by higher production tax credits. The increase in contributor to the variances.

2004 reflects higher taxable earnings and a decline inthe level of production tax credits due to the sale of interests insynfuel facilities. Outlook- We expect to continue to develop our proved areas, test unproved areas and prudently add new acreage in Michigan and Outlook- We may sell additional interests in our synfuel plants Texas. During 2005 we increased our acreage holdings by 38,437 and take actions to protect our expected synfuel cash flows from acres 124,852 net of the interest of others) in the Antrim and the risk of an oil price-related phase-out. Synfuel-related tax credits Barnett shales. Results from the Barnett shale test wells drilled expire on December 31, 2007. during 2005 are expected during the first half of 2006. We expect to invest a combined amount of approximately $100 million to Inthe third quarter of 2005, we executed an agreement to purchase $130 million in our unconventional gas business in 2006.

five on-site energy projects and closed on three of the projects in2005.

Power and Industrial Projects will continue leveraging its extensive Fuel Transportation and Marketing energy-related operating experience and project management Fuel Transportation and Marketing consists of DTE Energy Trading, capability to develop and grow the on-site energy business. We Coal Transportation and Marketing and the Pipelines, Processing expect solid earnings from our on-site energy business in2006. and Storage business.

Production tax credits generated by our Coal-Based Fuels and DTE Energy Trading focuses on physical power and gas marketing, Landfill Gas Recovery businesses are subject to the same phase structured transactions, enhancement of returns from DTE Energy's out risk if domestic crude oil prices reach certain levels. See Note 13. power plants and the optimization of contracted natural gas pipelines and storage capacity positions. Our customer base is predominantly utilities, local distribution companies, large industrials, Unconventional Gas Production and other marketing and trading companies. We enter into derivative Unconventional Gas Production isprimarily engaged in natural gas financial instruments as part of our marketing and hedging activities.

exploration, development and production. Our Unconventional Most of the derivative financial instruments are accounted for under Gas Production business produces gas from the Antrim and Barnett the mark-to-market method, which results in earnings recognition shales and sells most of the gas to the Fuel Transportation and of unrealized gains and losses from changes in the fair value of the Marketing segment. derivatives. We utilize forwards, futures, swaps and option contracts to mitigate risk associated with our marketing and trading activity Factors impacting income: Net income decreased $2million in as well as for proprietary trading within defined risk guidelines. DTE 2005 and decreased $6million in2004. The decline in 2005 isdue Energy Trading is integral in providing commodity risk management to higher operating and Michigan severance tax expenses. The services to the other unregulated businesses within DTE Energy.

decline in 2004 isdue to increased interest costs and a gain that was recognized in 2003 as a result of a sale of a non-core asset. Coal Transportation and Marketing provides fuel, transportation and rail equipment management services. We specialize in minimizing (inMillions) 2005 2004 2003 fuel costs and maximizing reliability of supply for energy-intensive Operating Revenues $ 74 $ 71 S 70 customers. Additionally, we participate incoal trading and coal-to-Operation and Maintenance 30 27 22 power tolling transactions, as well as the purchase and sale of Depreciation and Amortization 20 18 17 emissions credits. We recently initiated a new business line, coal Taxes OtherThan Income 11 7 7 mine methane extraction, in which we recover methane gas from Operating Income 13 19 24 mine voids for processing and delivery to natural gas pipelines, Other (Income) and Deductions 8 10 7 industrial users, or for small power generation projects.

Income Tax Provision 1 3 5 Net Income S 4 $ 6$ 12 Pipelines, Processing and Storage has a partnership interest in an interstate transmission pipeline, seven carbon dioxide processing Operating revenues increased $3million in 2005 and increased facilities and a natural gas storage field, as well as lease rights to

$1million in 2004 due primarily to higher gas prices. another natural gas storage field. The assets of these businesses are well integrated with other DTE Energy operations.

Operations and maintenance expenses increased $3million in 2005 and increased $5million in 2004. Increases are associated Factors impacting income: Net income decreased $116 million in with the addition of approximately 300 producing wells during the 2005, consisting primarily of a $131 million decline at DTE Energy three year period. The 2004 increase isalso due to a $6million Trading associated with mark-to-market losses on gas storage hedges.

pretax gain on the sale of non-core assets recorded in 2003. Net income increased $49 million in 2004, consisting primarily of a

$47 million improvement at DTE Energy Trading. The comparability Taxes other than income increased $4million in 2005 due to higher of results is impacted by a $74 million one-time pretax gain from a severance taxes associated with gas price increases. contract modification/termination recorded inthe first quarter of 2004 and significant 2005 mark-to-market losses on derivative contracts used to economically hedge our gas in storage and forward power contracts.

31

(inMillions) 2005 2004 2003 Other (income) and deductions for 2005 remained consistent with Operating Revenues $ 1,684 S 1,254 $ 1,061 2004, and decreased $25 million in2004. The decline in 2004 is Fuel, Purchased Power and Gas 970 473 643 primarily due to gains recorded in 2003 from selling our 16%

Operation and Maintenance 710 596 334 pipeline interest in the Portland Natural Gas Transmission System.

Depreciation and Amortization 7 6 4 Taxes Other Than Income 3 4 2 Income tax provision decreased $65 million in 2005 and increased Operating Income (Loss) (6) 175 78 $23 million in 2004 due to variations in earnings.

Other (Income) and Deductions (7) (7) (32)

Outlook- We expect to continue to grow our Coal Services and Income Tax Provision (Benefit) (1) 64 41 DTE Energy Trading businesses in a manner consistent with, and Netincome S 2 $ 118 $ 69 complementary to, the growth of our other business segments.

Gas storage and transportation capacity enhances our ability to Operating revenues increased $430 million in2005 and increased provide reliable and custom-tailored bundled services to large-volume

$193 million in 2004. Both Coal Transportation and Marketing and end users and utilities. This capacity, coupled with the synergies DTE Energy Trading experienced revenue growth in 2005 due to from DTE Energy's other businesses, positions the segment to add higher demand, higher commodity pricing, the sale of emission credits value and mitigate risks.

and increased trading volume. Comparability of 2005 to 2004 is affected because our trading operations recorded an adjustment in We expect to continue to grow our Pipeline, Processing and Storage 2004 that increased revenue by $86 million related to the modification business by expanding existing assets and developing new assets.

of afuture purchase commitment under atransportation agreement Pipelines, Processing and Storage received MPSC approval in with an interstate pipeline company. See Note 13. September 2005 and executed long-term contracts for acapacity expansion at one of our Michigan storage fields that will facilitate Coal Transportation and Marketing revenues in 2004 were affected an additional 14 Bcf of storage service sales starting in April 2006.

by our strategy to produce synfuel primarily from plants inwhich Vector Pipeline has secured long-term market commitments to support we had sold interests. This strategy resulted inthe reduction of an expansion project, for approximately 200 MMcf per day, with a synfuel production levels. We were contractually obligated to supply projected in-service date of November 2007. Vector Pipeline expects coal to customers at certain sites that did not produce synfuel as a to receive Federal Energy Regulatory Commission (FERC) approval result of our production strategy. To meet our obligations to provide inthe second quarter of 2006. The Millennium Pipeline filed an coal under long-term contracts with customers, we acquired coal that application for FERC approval in August 2005. Inaddition, Pipeline, was resold to customers. The coal was sold at prices higher than Processing and Storage owns a 10.5% interest in the Millennium the prices at which synfuel would have been sold to these customers. Pipeline and iscurrently negotiating to increase its equity interest.

Fuel, purchased powerand gas increased $497 million in 2005 and Significant portions of the Fuel Transportation and Marketing portfolio decreased $170 million in 2004. During 2005, our earnings have are economically hedged. The portfolio includes financial instruments been negatively impacted by the economically favorable decision and gas inventory, as well as capacity positions of natural gas in early 2005 to delay previously planned withdrawals from gas storage and pipelines and power transmission contracts. The storage due to a decrease in the current price for natural gas and financial instruments are deemed derivatives, whereas the gas an increase in the forward price for natural gas. We anticipate the inventory, pipelines and storage assets are not derivatives. As a financial impact of this timing difference will reverse when the gas result, we will experience earnings volatility as derivatives are iswithdrawn from storage in the current storage cycle and is sold marked to market without revaluing the underlying non-derivative at prices significantly in excess of the cost of gas instorage. In contracts and assets. The majority of such earnings volatility is addition, we entered into forward power contracts to economically associated with the natural gas storage cycle, which does not hedge certain physical and capacity power contracts. We expect coincide with the calendar and fiscal year, but runs annually from the timing difference on the forward power contracts will be fully April of one year to March of the next year. Our strategy is to realized by the end of 2007. economically hedge the price risk of storage with over-the-counter forwards and futures. Current accounting rules require the marking In2004, our trading operations recorded a gas inventory adjustment to market of forward sales and futures, but do not allow for the that increased expense by $12 million related to the termination of marking to market of the related gas inventory. This results in a long-term gas exchange agreement with an interstate pipeline gains and losses that are recognized indifferent interim and annual company. See Note 13. Under the gas exchange agreement, we accounting periods. We generally anticipate the financial impact received gas from the customer during the summer injection period of this timing difference will reverse by the end of each storage and redelivered the gas during the winter heating season. cycle. See 'Fair Value of Contracts" section that follows.

Operation and maintenance expenses increased $114 million in 2005 and increased $262 million in 2004. During 2005, our Coal Corporate & Other Transportation and Marketing business experienced higher Corporate & Other includes various corporate support functions throughput volumes and increased prices for coal. The increase in such as accounting, legal and information technology services. As 2004 was due primarily to increased coal purchases and increased these functions essentially support the entire Company, their costs lease expense. are fully allocated to the various segments based on services utilized.

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Therefore the effect of the allocation on each segment can vary Cumulative Effect Of Accounting Changes from year to year. Additionally, Corporate & Other holds certain non-utility debt, assets held for sale, and energy related investments. Inthe fourth quarter of 2005, we adopted additional new accounting rules for asset retirement obligations. The cumulative effect of adopting Factors impacting income: Corporate & Other results declined $40 these new accounting rules reduced 2005 earnings by $3million.

million in2005, compared to a $53 million improvement in2004.

The 2005 decline was primarily a result of the parent company not On January 1,2003, we adopted new accounting rules for asset allocating merger interest to Detroit Edison and MichCon. Partially retirement obligations and energy trading activities. The cumulative offsetting 2005 increased expenses were reduced Michigan Single effect of adopting these new accounting rules reduced 2003 earnings Business Taxes and gains on the sale of non-strategic assets. The by $27 million.

2004 improvement was affected by a $14 million net of tax gain from See Note 2.

the sale of 3.5 million shares of Plug Power stock, as well as lower Michigan Single Business Taxes, resulting from tax saving initiatives.

Corporate & Other also benefited from lower financing costs. Capital Resources and Liquidity DTE Energy and its subsidiaries require cash to operate and is Discontinued Operations provided by both internally and externally generated sources. We DTE Energy Technologies (Dtech)- We own Dtech, which assembles, manage our liquidity and capital resources to maintain financial markets, distributes and services distributed generation products, flexibility to meet our current and future cash flow needs.

provides application engineering, and monitors and manages on-site generation system operations. InJuly 2005, management approved Cash Requirements the restructuring of this business resulting inthe identification of certain assets and liabilities to be sold or abandoned, primarily We use cash to maintain and expand our electric and gas utilities associated with standby and continuous duty operations. We and to grow our non-utility businesses, retire and pay interest on recognized a net of tax restructuring loss of $23 million during the long-term debt and pay dividends. Our strategic direction anticipates third quarter of 2005 primarily representing the write down to fair base level capital investments and expenditures for existing businesses value of the assets of Dtech, less costs to sell, and the write-off of in 2006 of up to $1.2 billion. The capital needs of our utilities will goodwill. As we execute the restructuring plan, there may be increase due primarily to environmental related expenditures. We adjustments to amounts recorded related to the impairment and exit may spend an additional $200 million to $400 million on growth-costs. We anticipate completing the restructuring plan by mid-2006. related projects within our non-regulated businesses in 2006.

Southern Missouri Gas Company - We owned Southern Missouri Capital spending for general corporate purposes will increase in Gas Company (SMGC), a public utility engaged in the distribution, 2006, primarily as a result of DTE2 and environmental spending.

transmission and sale of natural gas insouthern Missouri. Inthe During 2005, we began the first wave of implementation of DTE2, first quarter of 2004, management approved the marketing of an enterprise resource planning system initiative to improve existing SMGC for sale. As of March 31, 2004, SMGC met the criteria of an processes and to implement new core information systems. We asset "held for sale" and we have reported its operating results as anticipate spending $165 million to $190 million over the next two a discontinued operation. We recognized a net of tax impairment years as the remaining system elements are developed and business loss of approximately $7million, representing the write-down to fair segments fully adopt DTE2.

value of the assets of SMGC, less costs to sell, and the write-off of allocated goodwill. InNovember 2004, we entered into a definitive We anticipate environmental capital expenditures of approximately agreement providing for the sale of SMGC. Regulatory approval $250 million in 2006 and up to approximately $2.3 billion of future was received in April 2005 and the sale closed in May 2005. capital expenditures to satisfy both existing and proposed new During the second quarter of 2005, we recognized a net of tax gain requirements.

of $2million.

We expect non-utility capital spending will approximate $200 million International Transmission Company- InFebruary 2003, we sold to $400 million annually for the next several years. Capital ITC, our electric transmission business, to affiliates of Kohlberg spending for growth of existing or new businesses will depend on Kravis Roberts & Co. and Trimaran Capital Partners, LLC. Through the existence of opportunities that meet our strict risk-return and December 31, 2004, we recorded a gain of $58 million (net of tax). value creation criteria.

During the second quarter of 2005, the gain was adjusted to $56 million (net of tax). Debt maturing in2006 totals approximately $682 million.

See Note 3. We believe that we will have sufficient internal and external capital resources to fund anticipated capital requirements.

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(inMillions) 2005 2004 2003 result of improved revenues and gross margin stemming from higher Cash and Cash Equivalents rates granted in the 2004 rate orders, warmer weather, and lower Cash Flow From (Used For) customer choice penetration. The offsetting increase in working Operating activities: capital requirements was driven by a$127 million PSCR under-Net income $ 537 $ 431 $ 521 recovery in 2005 as compared to a $112 million over-recovery in Depreciation, depletion 2004. Working capital requirements also reflect the higher cost of and amortization 872 744 691 gas at MichCon and our Fuel Transportation and Marketing segment.

Deferred income taxes 147 129 (220) MichCon's working capital and other requirements were $136 million Gain on sale of ITC, synfuel higher in 2005 compared to 2004 primarily due to the impact of and other assets, net (405) (236) (228) higher gas costs. This impact was reflected by accounts receivable Working capital and other (150) (73) 186 balances that were $198 million higher at December 31, 2005 than 1,001 995 950 the previous year at MichCon. The increase in working capital Investing activities: requirements was mitigated by lower income tax payments in 2005 Plant and equipment and company initiatives to improve cash flow, including better expenditures - utility (850) (815) (679) inventory management, cash sales transactions and the utilization Plant and equipment of letters of credit.

expenditures - non-utility (215) (89) (72)

Business acquisitions, Our net operating cash flow in 2004 was $995 million, reflecting a net of cash acquired (50) - - $45 million increase from 2003. The operating cash flow comparison Proceeds from sale of ITC, reflects an increase of over $300 million in net income, after synfuels and other assets, adjusting for non-cash items (depreciation, depletion, amortization, net of cash divested 409 325 758 deferred taxes and gains), substantially offset by a $259 million Restricted cash and increase inworking capital and other requirements. A portion of other investments (96) (102) 3 this improvement is attributable to the change in our strategy to (802) (681) 10 primarily produce synfuel from plants inwhich we have sold interests.

Financing activities: As previously discussed, synfuel projects generate operating losses, Issuance of long-term debt which have been more than offset by tax credits that we have been and common stock 1,041 777 571 unable to fully utilize, thereby negatively affecting operating cash Redemption of long-term debt (1,266) (759) (1,208) flow. Cash for working capital primarily reflects higher income tax Short-term borrowings, net 437 33 (44) payments of $172 million in 2004, reflecting a different payment Repurchase of common stock (13) - - pattern of taxes in2004 compared to 2003. The increase in working Dividends on common stock capital was mitigated by Company initiatives to improve cash flow, and other (366) (363) (358) including better inventory management, cash sales transactions, (167) (312) (1,039) deferral of retirement plan contributions and the utilization of letters of credit. Certain cash initiatives in2003 lowered cash flow in 2004.

Net Increase (Decrease) inCash and Cash Equivalents $ 32 $ 2$ (79)

Outlook- We expect cash flow from operations to increase over the long-term primarily due to improvements from utility rate Cash from Operating Activities increases and the sales of interests inour synfuel projects, partially offset by higher cash requirements on environmental and other utility A majority of the Company's operating cash flow is provided by our capital as well as growth investments in our non-utility portfolio.

two utilities, which are significantly influenced by factors such as We are likely to incur costs associated with implementation of our weather, electric Customer Choice, regulatory deferrals, regulatory Performance Excellence Process, but we expect to realize long term outcomes, economic conditions and operating costs. cost savings. We also may be impacted by the delayed collection of underrecoveries of our PSCR and GCR costs and electric and gas Our non-utility businesses also provide sources of cash flow to the accounts receivable as aresult of recent MPSC orders. Gas prices enterprise and reflect arange of operating profiles. The profiles are likely to be a source of volatility with regard to working capital vary from our synthetic fuels business, which we believe will provide requirements for the foreseeable future. We are continuing our approximately $1.2 billion of cash during 2006-2008 (assuming no efforts to identify opportunities to improve cash flow through phase-out), to new startups. These new start-ups include our working capital improvement initiatives.

unconventional gas and waste coal recovery businesses, which we are growing and, if successful, could require significant investment. Operating cash flow from our utilities isexpected to increase in 2006. Due to the structure of the interim and final rate orders, we Cash from operations totaling $1.001 billion in 2005 was up $6million will begin to realize the full benefits of interim and final rate relief from the comparable 2004 period. The operating cash flow comparison in 2006 when all customer rate caps expire. Improvements in cash reflects an increase of over $83 million in net income, after adjusting flow from our utilities are also expected from better management for non-cash items (depreciation, depletion, amortization, deferred of our working capital requirements, including the continued focus taxes and gains), substantially offset by a $77 million increase in on reducing past due accounts receivable. Our emphasis in these working capital and other requirements. Most of the improvement businesses will continue to be cash generation and conservation.

was driven by higher net income at Detroit Edison which was the 34

Assuming no production tax credit phase-out, cash flows from our on growth project investments increased $123 million in 2005 synfuel business are expected to be approximately $400 million, $500 while spending on environmental projects was $44 million higher million and $300 million in2006, 2007 and 2008, respectively, including than the 2004 period. The 2004 change was primarily due to proceeds

$300 million tax credit carryforward utilization by DTE Energy. received in 2003 totaling $758 million from the sale of ITC, interests The redeployment of this cash represents a unique opportunity to in three synfuel projects and non-strategic assets. Additionally, increase shareholder value and strengthen our balance sheet. the change was due to variations incash contractually designated We expect to use this cash to reduce debt, to continue to pursue for debt service.

growth investments that meet our strict risk-return and value creation criteria and to potentially repurchase common stock if Longer term, with the expected improvement at our utilities and adequate investment opportunities are not available. Our objectives assuming continued cash generation from the synfuel business, cash for cash redeployment are to strengthen the balance sheet and flows are expected to improve. We will continue to pursue opportunities coverage ratios to improve our current credit rating and outlook, to grow our businesses in a disciplined fashion if we can find and to replace the value of synfuel operations currently inherent opportunities that meet our strategic, financial and risk criteria.

in our share price. However, if oil prices remain at current levels or increase throughout 2006, the expected cash flow from the synfuel Cash from Financing Activities business would be less and could adversely impact the success of this strategy, unless the Company identifies alternative sources of We rely on both short-term borrowing and long-term financing as a cash. Synfuel cash flow consists of variable and fixed payments source of funding for our capital requirements not satisfied by the from partners, proceeds from option and other contracts used to Company's operations. Short-term borrowings, which are mostly protect us from risk of loss from a tax credit phase-out and the use inthe form of commercial paper borrowings, provide us with the of prior years' tax credit carry-forwards. Since 2004, we have liquidity needed on a daily basis. Our commercial paper program spent approximately $105 million hedging our future synfuel cash issupported by our unsecured credit facilities.

flow and may spend up to $50 million in 2006.

Our strategy isto have a targeted debt portfolio blend as to fixed Our other operating non-utility businesses are expected to and variable interest rates and maturity. We continually evaluate contribute approximately $500 million through 2008. Remaining our leverage target, which iscurrently 50% or lower, to ensure it is start-up businesses such as unconventional gas production, waste consistent with our objective to have a strong investment grade coal recovery and distributed generation will continue to use cash debt rating. We have completed a number of refinancings with the in excess of their cash generation over the next couple of years while effect of extending the average maturity of our long-term debt and they are being further developed. Certain of the previously discussed strengthening our balance sheet. The extension of the average maturity cash initiatives resulted inaccelerating the receipt of cash in2005, was accomplished at interest rates that lowered our debt costs.

which will have the impact of lowering cash flow in 2006.

Net cash used for financing activities improved $145 million in2005 and improved $727 million in 2004, compared to the prior periods.

Cash from Investing Activities The improvement in 2005 was primarily driven by the issuance of Cash inflows associated with investing activities are primarily common stock which resulted from the conversion of our equity generated from the sale of assets. Inany given year, we will look security units. The change in2004 was primarily due to higher to realize cash from under-performing or non-strategic assets. issuances of long-term debt and levels of short-term debt borrowings Capital spending within the utility business isprimarily to maintain our which exceeded the requirements of long-term debt redemptions.

generation and distribution infrastructure, comply with environmental regulations and gas pipeline replacements. Capital spending within See Note 9 - Long-Term Debt and Preferred Securities and Note our non-utility businesses isfor ongoing maintenance and expansion. 10 - Short-Term Credit Arrangements and Borrowings for more The balance of non-utility spending isfor growth, which we manage information regarding financing activities.

very carefully. We look to make investments that meet strict criteria interms of strategy, management skills, risks and returns. All new Amounts available under shelf registrations include $500 million investments are analyzed for their rates of return and cash payback at DTE Energy, $250 million at Detroit Edison and $200 million at on a risk adjusted basis. We have been disciplined in how we MichCon. In2006, we plan on filing new shelf registration deploy capital and will not make investments unless they meet our statements for DTE Energy and Detroit Edison.

criteria. For new business lines, we invest tentatively based on research and analysis. We start with a limited investment, we Common stock issuances or repurchases can also be a source or use of cash. InJanuary 2005, we announced that the DTE Energy evaluate results and either expand or exit the business based on those results. Inany given year, the amount of growth capital will Board of Directors has authorized the repurchase of up to $700 be determined by the underlying cash flows of the Company with a million in common stock through 2008. The authorization provides clear understanding of any potential impact on our credit ratings. Company management with flexibility to pursue share repurchases from time to time, and will depend on future cash flows and Net cash outflows relating to investing activities increased $121 investment opportunities. No share repurchases were made in million in 2005 and $691 million in 2004, compared to the prior 2005. As of January 1,2005, we discontinued issuing new DTE year. The 2005 change was primarily due to increased capital Energy shares for our dividend reinvestment plan, which generated expenditures, partially offset by higher synfuel proceeds. Spending approximately $50 million annually. We also contributed $170 million of DTE Energy common stock to our pension plan in the first quarter 35

of 2004. InAugust 2005, we issued 3.7 million shares of common Credit Rating Agency Moody's stock in conjunction with the settlement of the stock purchase Standard Investors Fitch component of our equity security units. Entity Description & Poors Service Ratings 0TE Energy Senior Unsecured Debt BBB- Baa2 BBB Commercial Paper A-2 P-2 F2 Contractual Obligations Detroit Edison Senior Secured Debt BBB+ A3 A-The following table details our contractual obligations for debt Commercial Paper A-2 P-2 F2 redemptions, leases, purchase obligations and other long-term MichCon Senior Secured Debt BBB A3 A-obligations as of December 31, 2005: Commercial Paper A-2 P-2 F2

.ess Than 1-3 4-5 After (inMillions) Total 1Year Years Years 5Years Critical Accounting Estimates Contractual Obligations There are estimates used in preparing the consolidated financial Long-term debt Mortgage bonds, statements that require considerable judgment. Such estimates notes and other $ 5,821 S 577 $ 634 $ 1,305 $ 3,305 relate to regulation, risk management and trading activities, Securitization bonds 1,400 105 363 290 642 production tax credits, goodwill, pension and postretirement costs, Equity-linked securities 175 175 - - the allowance for doubtful accounts, and legal and tax reserves.

Trust preferred-linked securities 289 289 Regulation Capital lease obligations 124 16 43 24 41 Interest 6,035 455 1,222 673 3,685 A significant portion of our business issubject to regulation. Detroit Operating leases 536 63 128 61 284 Edison and MichCon currently meet the criteria of Statement of Electric, gas, fuel, Financial Accounting Standards (SFAS) No. 71, Accounting for the transportation and storage Effects of Certain Types of Regulation. Application of this standard purchase obligations 11) 6,333 3,718 1,747 188 680 Other long-termn obligations 337 153 117 21 46 results in differences inthe application of generally accepted Total obligations $21,050 5,087 S 4,429 S 2562 $ 8,972 accounting principles between regulated and non-regulated (1)Excludes amounts associated with full requirements contracts where no stated businesses. SFAS No. 71 requires the recording of regulatory minimum purchase volume isrequired. assets and liabilities for certain transactions that would have been treated as revenue or expense in non-regulated businesses. Future regulatory changes or changes in the competitive environment Credit Ratings could result in discontinuing the application of SFAS No. 71 for Credit ratings are intended to provide banks and capital market some or all of our businesses. If we were to discontinue the participants with a framework for comparing the credit quality application of SFAS No. 71 on all our operations, we estimate that of securities and are not a recommendation to buy, sell or hold the extraordinary loss would be as follows:

securities. Management believes that the current credit ratings of the Company provide sufficient access to the capital markets. However, (inMillions) disruptions inthe banking and capital markets not specifically related Utility to the company may affect our ability to access these funding Detroit Edison (1) $ (154) sources or cause an increase inthe return required by investors. MichCon (43)

Total $ (197)

We have issued guarantees for the benefit of various non-utility (1)Excludes securitized regulatory assets subsidiaries. Inthe event that our credit rating is downgraded to below investment grade, certain of these guarantees would require Management believes that currently available facts support the us to post cash or letters of credit valued at approximately $536 continued application of SFAS No. 71 and that all regulatory assets million at December 31, 2005. Additionally, upon a downgrade, our and liabilities are recoverable or refundable in the current rate trading business could be required to restrict operations and our environment. See Note 4.

access to the short-term commercial paper market could be restricted or eliminated. While we currently do not anticipate such Risk Management and Trading Activities a downgrade, we cannot predict the outcome of current or future credit rating agency reviews. The following table shows our credit All derivatives are recorded at fair value and shown as 'Assets or rating as determined by three nationally respected credit rating liabilities from risk management and trading activities" inthe agencies. All ratings are considered investment grade and affect consolidated statement of financial position. Risk management the value of the related securities. activities are accounted for in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Through December 2002, trading activities were accounted for inaccordance with Financial Accounting Standards Board (FASB) Emerging Issues Task Force (EITF) Issue No. 98-10, Accounting for Energy Trading and Risk Management Activities.

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Effective January 2003, trading activities are accounted for in estimated cash flows are revised downward, the reporting unit accordance with SFAS No. 133. See Note 2. may be required to write down all or a portion of its goodwill, which would adversely impact our earnings.

The offsetting entry to "Assets or liabilities from risk management and trading activities" isto other comprehensive income or earnings As of December 31, 2005, our goodwill totaled $2.1 billion. The depending on the use of the derivative, how it is designated and majority of our goodwill isallocated to our utility reporting units, with if it qualifies for hedge accounting. The fair values of derivative $772 million allocated to the Gas Utility reporting unit. The value contracts were adjusted each reporting period for changes using of the utility reporting units may be significantly impacted by rate market sources such as: orders and the regulatory environment. The Gas Utility reporting unit iscomprised primarily of MichCon. We have made certain

published exchange traded market data assumptions for MichCon that incorporate earnings multiples used

prices from external sources in the cash flow valuations. These assumptions may change as

price based on valuation models regulatory and market conditions change.

Market quotes are more readily available for short duration contracts. We also have $41 million of goodwill allocated to the Power and Derivative contracts are only marked to market to the extent that Industrial Projects reporting unit. The value of the Power and markets are considered highly liquid where objective, transparent Industrial Projects reporting unit may be significantly impacted by prices can be obtained. Unrealized gains and losses are fully reserved any phase-out of tax credits related to our synfuel business. We for transactions that do not meet this criterion. have assumed there will be no phase-out of synfuel tax credits and will monitor the status of any potential phase-out and its impact Production Tax Credits on our valuation assumptions.

We generate production tax credits from our synfuel, coke battery During 2005 we recorded an impairment of $16 million to goodwill and landfill gas recovery operations. We recognize earnings as tax related to discontinuing the operations of Dtech.

credits are generated at our facilities in one of two ways. First, to the extent we have sold an interest in our synfuel facilities to third Based on our 2005 goodwill impairment test, we determined that parties, we recognize gains as synfuel is produced and sold, and the fair value of our remaining operating reporting units exceed when there ispersuasive evidence that the sales proceeds have their carrying value and no impairment existed. We will continue become fixed or determinable and collectibility isreasonably assured. to monitor our estimates and assumptions regarding future cash Second, to the extent we generate credits to our own account, we flows. While we believe our assumptions are reasonable, actual recognize earnings through reduced tax expense. results may differ from our projections.

All production tax credits are subject to audit by the IRS. However, Pension and Postretirement Costs all of our synfuel facilities have received favorable private letter rulings from the IRS with respect to their operations. Audits of five Our costs of providing pension and postretirement benefits are of our synfuel facilities were successfully completed inthe past two dependent upon a number of facfors, including rates of return on years. If production tax credits were disallowed in whole or in part plan assets, the discount rate, the rate of increase in health care as a result of an IRS audit, there could be a significant write-off of costs and the amount and timing of plan sponsor contributions.

previously recorded earnings from such tax credits.

We had pension costs for qualified pension plans of $90 million in Tax credits generated by our facilities were $617 million in 2005, 2005, $81 million in 2004, and $47 million in 2003. Postretirement as compared to $449 million in 2004 and $387 million in 2003. The benefits costs for all plans were $155 million in2005, $125 million portion of tax credits generated for our own account was $55 million in 2004, and $118 million in 2003. Pension and postretirement in 2005, as compared to $38 million in 2004 and $241 million in2003, benefits costs for 2005 are calculated based upon a number of with the remaining credits generated allocated to third party partners. actuarial assumptions, including an expected long-term rate of return on our plan assets of 9.0%. Indeveloping our expected long-term rate of return assumption, we evaluated input from our Goodwill consultants, including their review of asset class risk and return Certain of our business units have goodwill resulting from purchase expectations as well as inflation assumptions. Projected returns business combinations. Inaccordance with SFAS No. 142, Goodwill are based on broad equity and bond markets. Our 2006 expected and Other Intangible Assets, each of our reporting units with good- long-term rate of return on plan assets is based on an asset will is required to perform impairment tests annually or whenever allocation assumption utilizing active investment management of events or circumstances indicate that the value of goodwill may be 66% in equity markets, 25% in fixed income markets, and 9%

impaired. Inorder to perform these impairment tests, we must invested inother assets. Because of market volatility, we periodically determine the reporting unit's fair value using valuation techniques, review our asset allocation and rebalance our portfolio when which use estimates of discounted future cash flows to be generated considered appropriate. Given market conditions, we believe that by the reporting unit. These cash flow valuations involve a number 8.75% isa reasonable long-term rate of return on our plan assets of estimates that require broad assumptions and significant judgment for 2006. We will continue to evaluate our actuarial assumptions, by management regarding future performance. To the extent including our expected rate of return, at least annually.

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We base our determination of the expected return on qualified plan Pension and postretirement costs and pension cash funding assets on a market-related valuation of assets, which reduces year- requirements may increase in future years without substantial to-year volatility. This market-related valuation recognizes changes in returns in the financial markets. We made a$222 million cash fair value in asystematic manner over a three-year period. Accordingly, contribution in 2003 and a$170 million contribution to our pension the future value of assets will be impacted as previously deferred plan inthe form of DTE Energy common stock in 2004. We did not gains or losses are recorded. We have unrecognized net losses due to make pension contributions in2005. We contributed $80 million to the performance of the financial markets. As of December 31, our postretirement plans in 2004. We did not contribute to our 2005, we had $6million of cumulative losses that remain to be postretirement plans in 2003 and 2005. We do not anticipate recognized inthe calculation of the market-related value of assets. making a contribution to our qualified pension plans in 2006. At the discretion of management, we may make up to a $120 million The discount rate that we utilize for determining future pension contribution to our postretirement plans in 2006.

and postretirement benefit obligations isbased on a yield curve approach and a review of bonds that receive one of the two highest In December 2003, the Medicare Prescription Drug, Improvement ratings given by a recognized rating agency. The yield curve approach and Modernization Act was signed into law. This Act provides for matches projected plan pension and postretirement benefit payment a federal subsidy to sponsors of retiree health care benefit plans streams with bond portfolios reflecting actual liability duration that provide a benefit that isat least actuarially equivalent to the unique to our plans. The discount rate determined on this basis benefit established by law. The effects of the subsidy on the decreased from 6.0% at December 31, 2004 to 5.9% at December measurement of net periodic postretirement benefit costs reduced 31, 2005. Due to recent financial market performance, lower costs by $20 million in 2005 and $16 million in2004.

discount rates and increased health care trend rates, we estimate that our 2006 pension costs will approximate $80 million compared See Note 14.

to $96 million in 2005 and our 2006 postretirement benefit costs will approximate $192 million compared to $155 million in 2005. Allowance for Doubtful Accounts Inthe last several years, we have made modifications to the We establish an allowance for doubtful accounts based upon factors pension and postretirement benefit plans to mitigate the earnings surrounding the credit risk of specific customers, historical trends, impact of higher costs. Future actual pension and postretirement economic conditions, age of receivables and other information.

benefit costs will depend on future investment performance, Higher customer bills due to increased gas prices, the lack of changes in future discount rates and various other factors related adequate levels of assistance for low-income customers and to plan design. Additionally, future pension costs for Detroit Edison economic conditions have also contributed to the increase in past will be affected by a pension tracking mechanism, which was due receivables. As a result of these factors, our allowance for authorized by the MPSC in its November 2004 rate order. The doubtful accounts increased in 2004 and 2005. We believe the tracking mechanism provides for the recovery or refunding of pension allowance for doubtful accounts is based on reasonable estimates.

costs above or below the amount reflected inDetroit Edison's base As part of the 2005 rate order for MichCon, the MPSC provided for the rates. InApril 2005, the MPSC approved the deferral of the non-establishment of an uncollectible accounts tracking mechanism that capitalized portion of MichCon's negative pension expense. MichCon partially mitigates the impact associated with MichCon uncollectible will record a regulatory liability for any negative pension costs, as expenses. However, failure to make continued progress in collecting determined under generally accepted accounting principles.

our past due receivables in light of rising energy prices would Lowering the expected long-term rate of return on our plan assets unfavorably affect operating results and cash flow.

by one-percentage-point would have increased our 2005 qualified pension costs by approximately $24 million. Lowering the discount Legal and Tax Reserves rate and the salary increase assumptions by one-percentage-point We are involved in various legal and tax proceedings, claims and would have increased our 2005 pension costs by approximately litigation arising in the ordinary course of business. We regularly

$10 million. Lowering the health care cost trend assumptions by assess our liabilities and contingencies in connection with asserted one-percentage-point would have decreased our postretirement or potential matters, and establish reserves when appropriate. Legal benefit service and interest costs for 2005 by approximately $20 million. reserves are based upon management's assessment of pending and threatened legal proceedings and claims against the Company.

The market value of our pension and postretirement benefit plan Tax reserves are based upon management's assessment of potential assets has been affected by the financial markets. The value of our adjustments to tax positions taken. We regularly review ongoing plan assets increased from $2.9 billion at December 31, 2003 to tax audits and prior audit experience, in addition to current tax and

$3.3 billion at December 31, 2004. The value at December 31, 2005 accounting authority in assessing potential adjustments.

was $3.3 billion. The investment performance returns and declining discount rates required us to recognize an additional minimum pension liability, an intangible asset and an entry to other compre- Environmental Matters hensive loss (shareholders' equity) in 2003, 2004, and 2005. The additional minimum pension liability and related accounting entries Protecting the environment, as well as correcting past environmental will be reversed on the balance sheet infuture periods if the fair damage, continues to be'a focus of state and federal regulators.

value of plan assets exceeds the accumulated pension benefit Legislation and/or rulemaking could further impact the electric obligations. The recording of the minimum pension liability does utility industry including Detroit Edison. The U.S. Environmental not affect net income or cash flow. Protection Agency (EPA) and the Michigan Department of 38

Environmental Quality (MDEQ) have aggressive programs to clean-up determinations, we have recorded liabilities of $35 million and contaminated property. $1million for the MGPs and other contaminated sites, respectively.

It is estimated that Gas Utility may incur $5million inexpenses Electric Utility related to cleanup costs in 2006. While we cannot make any assurances, we believe that acost deferral and rate recovery mechanism Air- Detroit Edison is subject to EPA ozone transport and acid rain for the MGP sites, approved by the MPSC, will prevent these costs regulations that limit power plant emissions of sulfur dioxide and from having a material adverse impact on our results of operations.

nitrogen oxides. InMarch 2005, EPA issued additional emission reduction regulations relating to ozone, fine particulate, regional haze In1993, acost deferral and rate recovery mechanism was approved and mercury air pollution. The new rules will lead to additional controls by the MPSC for investigation and remediation costs incurred at on fossil-fueled power plants to reduce nitrogen oxide, sulfur dioxide former MGP sites in excess of this reserve. Gas Utility employed and mercury emissions. To comply with these requirements, Detroit outside consultants to evaluate remediation alternatives for these Edison has spent approximately $644 million through 2005. We sites, to assist in estimating its potential liabilities and to review estimate Detroit Edison will incur future capital expenditures of up its archived insurance policies. As a result of these studies, Gas to $218 million in 2006 and up to $2.2 billion of additional capital Utility accrued an additional liability and a corresponding regulatory expenditures through 2018 to satisfy both the existing and pro- asset of $35 million during 1995. During 2005, we spent approximately posed new control requirements. Under the June 2000 Michigan $4million investigating and remediating these former MGP sites.

restructuring legislation, beginning January 1,2004, annual return InDecember 2005, we retained multiple environmental consultants of and on this capital expenditure was deferred in ratemaking until to estimate the projected cost to remediate each MGP site. We December 31, 2005, the expiration of the rate cap period. accrued an additional $9million in remediation liabilities associated with two of our MGP sites, to increase the reserve balance to $35 The EPA has ongoing enforcement actions against several major million at December 31, 2005.

electric utilities citing violations of new source provisions of the Clean Air Act. Detroit Edison received and responded to information Any significant change inassumptions, such as remediation requests from the EPA on this subject. The EPA has not initiated techniques, nature and extent of contamination and regulatory proceedings against Detroit Edison. InOctober 2003, the EPA requirements, could impact the estimate of remedial action costs promulgated revised regulations to clarify new source review for the sites and thereby affect the Company's financial position and provisions going forward. Several states and environmental cash flows. However, we anticipate the cost deferral and rate recovery organizations have challenged these regulations and, in December mechanism approved by the MPSC will prevent environmental costs 2003, a stay was issued until the U.S. Court of Appeals D.C. Circuit from having a material adverse impact on our results of operations.

renders an opinion in the case. We cannot predict the future impact of this issue upon Detroit Edison. Other Water- Detroit Edison isrequired to examine alternatives for Our non-utility affiliates are subject to a number of environmental reducing the environmental impacts of the cooling water intake laws and regulations dealing with the protection of the environment structures at several of its facilities. Based on the results of the from various pollutants. We are inthe process of installing new studies to be conducted over the next several years, Detroit Edison environmental equipment at our coke battery facilities in Michigan.

may be required to install additional control technologies to reduce We expect the projects to be completed within two years at a cost the impacts of the intakes. It isestimated that we will incur up to of approximately $25 million. Our other non-utility affiliates are

$50 million over the next four to six years in additional capital substantially in compliance with all environmental requirements.

expenditures to comply with these requirements.

Various state and federal laws regulate our handling, storage and ContaminatedSites - Detroit Edison conducted remedial investiga- disposal of waste materials. The EPA and the MDEQ have aggressive tions at contaminated sites, including two former MGP sites, the programs to manage the clean up of contaminated property. We have area surrounding an ash landfill and several underground and extensive land holdings and, from time to time, must investigate aboveground storage tank locations. We have a reserve balance of claims of improperly disposed contaminants. We anticipate our

$13 million as of December 31, 2005 for the remediation of these utility and non-utility companies may periodically be included in sites over the next several years. various types of environmental proceedings.

Gas Utility DTE2 ContaminatedSites - Prior to the construction of major interstate In2003, we began the development of DTE2, an enterprise resource natural gas pipelines, gas for heating and other uses was planning (ERP) system initiative to improve existing processes and manufactured locally from processes involving coal, coke or oil. Gas to implement new core information systems, relating to finance, Utility owns, or previously owned, 15 former MGP sites. Investigations human resources, supply chain and work management. As part of have revealed contamination related to the by-products of gas this initiative, we are implementing Enterprise Business Systems manufacturing at each site. Inaddition to the MPG sites, Gas software including, among others, products developed by SAP AG Utility isalso in the process of cleaning up other contaminated and MRO Software, Inc. The first phase of implementation sites. Cleanup activities associated with these sites will be occurred in 2005 inthe regulated electric fossil generation unit. Full conducted over the next several years. As a result of these implementation throughout the Company isnot anticipated until 2007.

39

The conversion of data and the implementation and operation of the Detroit Edison became a non-transmission owning member of MISO ERP will be continuously monitored and reviewed and should ultimately in compliance with section 10w (1)of PA 141. The MPSC has strengthen our internal control structure and lead to increased cost ordered that MISO costs charged to Detroit Edison should be efficiencies. Although our implementation plan includes detailed testing recovered through the PSCR mechanism.

and contingency arrangements to ensure a smooth and successful transition, we can provide no assurance that complications will not arise that could interrupt our operations. Federal Energy Policy Act of 2005 InAugust 2005, the Energy Policy Act of 2005 (Energy Act) was We have spent approximately $210 million through the end of signed into law. Among other provisions, the Energy Act:

2005 and expect total spending over the life of the project to be between $375 million and $400 million. We expect the benefits

establishes mandatory electric reliability standards; of lower costs, faster business cycles, repeatable and optimized

repeals the Public Utility Holding Company Act of 1935; processes, enhanced internal controls, improvements in inventory management and reductions in system support costs to outweigh

renews the Price Anderson Act for twenty years which provides the expense of our investment in this initiative. liability protection for nuclear power plants;

increases funding levels for the Low-Income Home Energy Assistance Program; and Midwest Independent System

increases FERC oversight responsibilities for the electric Operator (MISO) utility industry.

The MISO was formed in 1996 by its member transmission owners The implementation of the Energy Act requires proceedings at the and in December 2001 received FERC approval as a Regional state level and development of regulations by the FERC, as well as Transmission Organization (RTO) authorized to provide regional other federal agencies. The impact of the Energy Act on our results transmission services as prescribed by FERC in its Order 2000. of operations will depend on the implementation of final rules and Order 2000 requires an RTO to perform eight functions, including cannot be fully determined at this time.

tariff administration, transmission system congestion management, provision of ancillary services to support transmission operations, market monitoring, interregional coordination and the coordination NewAccounting Pronouncements of system planning and expansion. MISO's independence from See Note 2-New Accounting Pronouncements for discussion of ownership of either generation or transmission facilities isintended new pronouncements.

to enable it to ensure fair access to the transmission grid, and through its congestion management role, MISO isalso charged with ensuring grid reliability. MISO's initial provision of transmission FairValue of Contracts services in December 2001 was known as fay 1 operations.

The following disclosures are voluntary and provide enhanced Inkeeping with Order 2000, which permits RTOs to provide real-time transparency of the derivative activities and position of our trading energy imbalance services and a market-based mechanism for businesses and our other businesses.

congestion management, MISO, on April 1,2005, launched its Midwest Energy Market, or Day 2 operations, and began regional We use the criteria in Statement of Financial Accounting Standards wholesale electric market operations and transmission service No. 133, Accounting for Derivative Instruments and Hedging Activities, throughout its area. A key feature of the Midwest Energy Market as amended and interpreted, to determine if certain contracts must isthe establishment of Locational Marginal Prices (LMPs) which be accounted for as derivative instruments. The rules for determining provide price transparency for the sale and purchase of wholesale whether a contract meets the criteria for derivative accounting are electricity at different locations in the market territory. The LMP numerous and complex. Moreover, significant judgment isrequired isthe market clearing price at a specific pricing location in the to determine whether a contract requires derivative accounting, Midwest Energy Market that isequal to the cost of supplying the and similar contracts can sometimes be accounted for differently.

next increment of load at that location. The value of an LMP isthe If a contract isaccounted for as a derivative instrument, it is same whether a purchase or sale ismade at that location. Detroit recorded inthe financial statements as "assets or liabilities from Edison participates in the Midwest Energy Market by offering its risk management and trading activities", at the fair value of the generation on a day-ahead and real time basis and by bidding for contract. The recorded fair value of the contract isthen adjusted power in the market to serve its load. The cost of power procured quarterly to reflect any change in the fair value of the contract, a from the market net of any gain realized from generation sold into practice known as mark to market (MTM) accounting.

the market isincluded and recovered through the PSCR mechanism.

Inaddition, LMPs are expected to encourage new generation to Fair value represents the amount at which willing parties would locate where the power produced isof most value to the load and transact an arms-length transaction. To determine the fair value isexpected to identify where new transmission facilities are needed of contracts accounted for as derivative instruments, we use a to relieve grid congestion. combination of quoted market prices and mathematical valuation models. Valuation models require various inputs, including forward MISO is compensated for assuring grid reliability and for supporting prices, volatility, interest rates, and exercise periods.

the energy market through FERC-approved rates charged to load.

40

Contracts we typically classify as derivative instruments are power, * "Economic Hedges" represents derivative activity associated with gas and oil forwards, futures, options and swaps, as well as foreign assets owned and contracted by DTE Energy, including forward currency contracts. Items we do not generally account for as sales of gas production and trades associated with owned derivatives (and which are therefore excluded from the following transportation and storage capacity. Changes in the value of tables) include gas inventory, gas storage and transportation derivatives inthis category economically offset changes in the arrangements, full-requirements power contracts and gas and oil value of underlying non-derivative positions, which do not qualify reserves. As subsequently discussed, we have fully reserved the for fair value accounting. The difference in accounting treatment value of derivative contracts beyond the liquid trading timeframe of derivatives in this category and the underlying non-derivative thereby not impacting income. positions can result insignificant earnings volatility as discussed in more detail inthe preceding Results of Operations section.

The subsequent tables contain the following four categories repre- * "Other Non-Trading Activities" primarily represent derivative sented by their operating characteristics and key risks. activity associated with our Michigan gas reserves and synfuel operations. A substantial portion of the price risk associated

"Proprietary Trading" represents derivative activity transacted with the gas reserves has been mitigated through 2013.

with the intent of taking aview, capturing market price Changes inthe value of the hedges are recorded as "assets or changes, or putting capital at risk. This activity is speculative liabilities from risk management and trading activities", with an in nature as opposed to hedging an existing exposure. offset in other comprehensive income to the extent that the

'Structured Contracts" represents derivative activity transacted hedges are deemed effective. Oil-related derivative contracts with the intent to capture profits by originating substantially have been executed to economically hedge cash flow risks hedged positions with wholesale energy marketers, utilities, related to underlying, non-derivative synfuel related positions retail aggregators and alternative energy suppliers. Although through 2007. The amounts shown inthe following tables transactions are generally executed with a buyer and seller exclude the value of the underlying gas reserves and synfuel simultaneously, some positions remain open until a suitable proceeds including changes therein.

offsetting transaction can be executed.

Roll-Forward of Mark to Market Energy Contract Net Assets The following tables provide details on changes in our mark to market net asset or (liability) position during 2005:

Trading Activities (Ither Proprietary Structured . Economic Non--Trading (inMillions) Trading Contracts Hedges Total Activities Total MTM at December31, 2004 $ 3 $ 23 $ (98) $ (72) S (100) $ (172)

Reclassed to realized upon settlement (2) (16) 32 14 66 80 Changes infair value recorded to income 6 (91) (58) (143) 43 (100)

Amortization of option premiums - - (3) (3) (26) (29)

Amounts recorded to unrealized income 4 (107) (29) (132) 83 (49)

Amounts recorded in OCI (Note 1) - (54) 17 (37) (187) (224)

Option premiums paid and other (115) 2 - (113) 64 (49)

MTM at December31, 2005 $ (108) $ (136) S (110) $ (354) $ (140) S (494)

The following table provides acurrent 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, 2005. Amounts that relate to contracts that become due within twelve months are classified as current and all remaining amounts are classified as noncurrent.

Trading Activities Other Proprietary Structured Economic Non-Trading Total Assets (inMillions) Trading - Contracts Hedges Eliminations Totals Activities (Liabilities)

Current assets $ 295 $ 161 $ 205 $ (3) $ 658 S 148 $ 806 Noncurrent assets 9 53 186 (6) 242 74 316 Total MTM assets 304 214 391 (9) 900 222 1,122 Current liabilities (359) (232) (301) 3 (889) (200) (1,089)

Noncurrent liabilities (53) .- (118) (200) 6 (365) (162) (527)

Total MTM liabilities (412) (350) (501) 9 (1,254) (362) (1,616)

Total MTM net assets liabilities) $ (108) $ (136) $ (110) $ - $ (354) $ (140) S (494) 41

Maturity of Fair Value of MTM Energy landfill gas recovery operations are subject to phase-out if domestic Contract Net Assets crude oil prices reach certain levels. We have entered into a series of derivative contracts for 2006 through 2007 to economically hedge We fully reserve all unrealized gains and losses related to periods the impact of oil prices on a portion of our synfuel cash flow.

beyond the liquid trading timeframe. Our intent isto recognize MTM activity only when pricing data isobtained from active quotes See Note 12.

and published indexes. Actively quoted and published indexes include exchange traded (i.e., NYMEX) and over-the-counter positions for Credit Risk which broker quotes are available. Although the NYMEX has currently quoted prices for the next 72 months, broker quotes for gas and power are generally available for 18 and 24 months into Bankruptcies the future, respectively, we fully reserve all unrealized gains and We purchase and sell electricity, gas, coal, coke and other energy losses related to periods beyond the liquid trading timeframe and products from and to numerous companies operating inthe steel, which therefore do not impact income. automotive, energy, retail and other industries. Certain of our customers have filed for bankruptcy protection under Chapter 11 of As a result of adherence to generally accepted accounting principles, the U.S.Bankruptcy Code. We regularly review contingent matters the tables above do not include the expected favorable earnings relating to these customers and our purchase and sale contracts impacts of certain non-derivative gas storage and power contracts. and we record provisions for amounts considered at risk of probable We entered into economically favorable transactions in early 2005 loss. We believe our previously accrued amounts are adequate for to delay previously planned withdrawals from gas storage due to a probable loss. The final resolution of these matters is not expected decrease in the current price for natural gas and an increase in the to have a material effect on our financial statements.

forward price for natural gas. We anticipate the financial impact of this timing difference will reverse when the gas iswithdrawn from Other storage inthe current storage cycle and issold at prices significantly We engage in business with customers that are non-investment in excess of the cost of gas in storage. Inaddition, we entered into grade. We closely monitor the credit ratings of these customers forward power contracts to economically hedge certain physical and and, when deemed necessary, we request collateral or guarantees capacity power contracts. We expect the timing difference on the from such customers to secure their obligations.

forward power contracts will be fully realized by the end of 2007.

The table below shows the maturity of our MTM positions: We utilize both external and internally generated credit assessments when determining the credit quality of our trading counterparties.

(inMilrions) Total The following table displays the credit quality of our trading Fair Source of Fair Value 2006 2007 2008 Value counterparties as of December 31, 2005:

Proprietary Trading $ (64) S (441 $ - $ (108) Credit Exposure Net Structured Contracts (71) (611 (4) (1361 before Cash Credit (inMillions) Collateral Collateral Exposure Economic Hedges (96) (41 (10) (110)

Investment Grade (1)

TotalTradingActivities (231) (109) (141 (354)

A- and Greater S 444 S (46) $ 398 Other Non-Trading Acvities (52) (63) (25) (140)

BBB+ and BBB 290 (9) 281 Total S (2831 $ (172) $ (391 S (494)

BBB- 17 - 17 Total Investment Grade 751 (55) 696 Quantitative and Qualitative Non-investment grade (2) 52 (13) 39 Disclosures About Market Risk Internally Rated - investment grade (3) 129 (9) 120 Internally Rated -non-investment grade (4) 11 - 11 Commodity Price Risk Total $ 943 $ (77)$ 866 DTE Energy has commodity price risk arising from market price (Il This category includes counterparties with minimum credit ratings of Baa3 assigned by fluctuations in conjunction with the anticipated purchases of coal, Moody's Investors Service (Moody's) and B1B-assigned by Standard & Poor's Rating Group (Standard & Poor's). The five largest counterparty exposures combined for this uranium, and electricity to meet its obligations during periods of category represented 29%of the total gross credit exposure.

peak demand. We also are exposed to the risk of market price (2)This category includes counterparties with credit ratings that are below investment fluctuations on gas sale and purchase contracts, gas production grade. The five largest counterparty exposures combined for this category represented less than 5%of the total gross credit exposure.

and gas inventories. To limit our exposure to commodity price (3)This category includes counterparties that have not been rated by Moody's or Standard fluctuations, we have entered into a series of electricity and gas & Poor's, but are considered investment grade based on 0TE Energy's evaluation of futures, forwards, option and swap contracts. Commodity price the counterparty's creditworthiness. The five largest counterparty exposures combined for this category represented 7%of the total gross credit exposure.

risk associated with our electric and gas utilities is limited due to (4)This category includes counterparties that have not been rated by Moody's or the PSCR and GCR mechanisms. See Note 1. Standard & Poor's, and are considered non-investment grade based on OTE 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.

Our Coal-Based Fuels and Landfill Gas Recovery businesses are also subject to crude oil price risk. As previously discussed, production tax credits generated by DTE Energy's synfuel, coke battery and 42

Interest Rate Risk contracts through 2008. Additionally, we may enter into fair value currency hedges to mitigate changes inthe value of contracts or loans.

DTE Energy is subject to interest rate risk inconnection with the issuance of debt and preferred securities. Inorder to manage interest costs, we use treasury locks and interest rate swap agreements. Summary of Sensitivity Analysis Our exposure to interest rate risk arises primarily from changes in We performed a sensitivity analysis to calculate the fair values of U.S. Treasury rates, commercial paper rates and London Inter-Bank our commodity contracts, long-term debt instruments and foreign Offered Rates ILIBOR). As of December 31, 2005, the Company has currency forward contracts. The sensitivity analysis involved a floating rate debt to total debt ratio of approximately 15% increasing and decreasing forward rates at December 31, 2005 by (excluding securitized debt). a hypothetical 10% and calculating the resulting change in the fair values. The results of the sensitivity analysis calculations follow:

Foreign Currency Risk (inMillions) Assuming Assuming DTE Energy has foreign currency exchange risk arising from market a 10%0 a I0/

increase decrease Change inthe price fluctuations associated with fixed priced contracts. These Activity inrates inrates fair value of contracts are denominated in Canadian dollars and are primarily Gas Contracts $ (9) $ 7 Commodity contracts for the purchase and sale of power as well as for long-term and options transportation capacity. To limit our exposure to foreign currency Power Contracts $ (20) $ 21 Commodity contracts fluctuations, we have entered into a series of currency forward Oil Contracts $ 39 $ (40) Commodity options Interest Rate Risk $ (296) $ 318 Long-term debt Foreign Currency Risk $ 3 $ (3) Forward contracts Reporofanag~ee 7ResonsibiIify.f&rinanciaI Statemnents.

d rn o 1Y1:R Financial Statements DTE Energy Company management assessed the effectiveness of the company's internal control over financial reporting as of We have reviewed this annual report to shareholders, and December 31, 2005. Inmaking this assessment, it used the based on our knowledge, this annual report does not contain any criteria set forth by the Committee of Sponsoring Organizations of untrue statement of a material fact or omit to state a material the Treadway Commission (COSO) in Internal Control - Integrated fact necessary to make the statements made, in light of the Framework. Based on our assessment, management believes circumstances under which such statements were made, not that, as of December 31, 2005, DTE Energy Company's internal misleading with respect to the period covered by this annual control over financial reporting was effective based on those criteria.

report. Also, based on our knowledge, the financial statements, and other financial information included in this annual report, Our management's assessment of the effectiveness of the fairly present in all material respects the financial condition, company's internal control over financial reporting has been results of operations and cash flows of DTE Energy as of, and audited by DTE Energy's independent registered public accounting for, the periods presented. firm, as stated in their report which is included herein.

Internal Control Over Financial Reporting The management of DTE Energy Company is responsible for establishing and maintaining adequate internal control over financial reporting. DTE Energy Company's internal control Anthony F.Earley Jr.

system was designed to provide reasonable assurance to the Chairman and Chief Executive Officer company's management and board of directors regarding the preparation and fair presentation of published financial statements.

All 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 David E.Meador to financial statement preparation and presentation. Projections Executive Vice President and Chief Financial Officer of any evaluation of the effectiveness to future periods are subject to the risks that control may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

43

DT~egy. ompany~4`

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XALCX ~ 1.:.- , . d U To the Board of Directors and Shareholders of DTE Energy Company: preparation of financial statements inaccordance with generally accepted accounting principles, and that receipts and expenditures of the company are We have audited management's assessment, included inthe accompanying being made only inaccordance with authorizations of management and directors Management's report on internal control over financial reporting, that OTE Energy of the company; and (3)provide reasonable assurance regarding prevention or Company and subsidiaries (the Company') maintained effective internal control timely detection of unauthorized acquisition, use, or disposition of the company's over financial reporting as of December 31, 2005, based on criteria established in assets that could have a material effect on the financial statements.

Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is Because of the inherent limitations of internal control over financial reporting, responsible for maintaining effective internal control over financial reporting including the possibility of collusion or improper management override of controls, and for its assessment of the effectiveness of internal control over financial material misstatements due to error or fraud may not be prevented or detected reporting. Our responsibility is to express an opinion on management's assessment on a timely basis. Also, projections of any evaluation of the effectiveness of the and an opinion on the effectiveness of the Company's internal control over internal control over financial reporting to future periods are subject to the risk financial reporting based on our audit. that the controls may become inadequate because of changes inconditions, or that the degree of compliance with the policies or procedures may deteriorate.

We conducted our audit inaccordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we Inour opinion, management's assessment that the Company maintained effective plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting as of December 31, 2005, isfairly stated, internal control over financial reporting was maintained in all material respects. in all material respects, based on the criteria established in Internal Control-Our audit included obtaining an understanding of internal control over financial Integrated Framework issued by the Committee of Sponsoring Organizations of reporting, evaluating management's assessment testing and evaluating the the Treadway Commission. Also in our opinion, the Company maintained, in all design and operating effectiveness of internal control, and performing such other material respects, effective internal control over financial reporting as of December procedures as we considered necessary in the circumstances. We believe that 31, 2005, based on the criteria established inInternal Control-integrated Framework our audit provides a reasonable basis for our opinions. issued by the Committee of Sponsoring Organizations of the Treadway Commission.

A company's internal control over financial reporting is a process designed by, We have also audited, in accordance with the standards of the Public Company or under the supervision of, the company's principal executive and principal Accounting Oversight Board (United States), the consolidated financial statements financial officers, or persons performing similar functions, and effected by the of the Company as of December 31, 2005 and for the year then ended; and our company's board of directors, management, and other personnel to provide report dated March 7,2006 expressed an unqualified opinion on those consolidated reasonable assurance regarding the reliability of financial reporting and the financial statements.

preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1)pertain to LLP Deloitte.

the maintenance of records that, in reasonable detail, accurately and fairly Detroit, Michigan Deloitte &Touche LLP reflect the transactions and dispositions of the assets of the company; (2)provide March 7,2006 Suite 900, 600 Renaissance Center reasonable assurance that transactions are recorded as necessary to permit Detroit Michigan 48243-1704 To the Board of Directors and Shareholders of DTE Energy Company: in conformity with accounting principles generally accepted inthe United States of America.

We have audited the consolidated statement of financial position of DTE Energy Company and subsidiaries (the 'Company') as of December 31, 2005 and 2004, As discussed in Note 2 to the consolidated financial statements, in connection and the related consolidated statements of operations, cash flows, and changes with the required adoption of certain new accounting principles, in 2005 the in shareholders' equity and comprehensive income for each of the three years Company changed its method of accounting for asset retirement obligations in the period ended December 31, 2005. These financial statements are the and in2003 the Company changed its method of accounting for asset retire-responsibility of the Company's management. Our responsibility is to express ment obligations, energy trading contracts and gas inventories.

an opinion on the consolidated financial statements based on our audits.

We have also audited, in accordance with the standards of the Public We conducted our audits inaccordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company Accounting Oversight Board (United States). Those standards require Company's internal control over financial reporting as of December 31, 2005, that we plan and perform the audit to obtain reasonable assurance about whether based on the criteria established in Internal Control-Integrated Framework the financial statements are free of material misstatement. An audit includes issued by the Committee of Sponsoring Organizations of the Treadway examining, on a test basis, evidence supporting the amounts and disclosures Commission and our report dated March 7, 2006 expressed an unqualified in the financial statements. An audit also includes assessing the accounting opinion on management's assessment of the effectiveness of the Company's principles used and significant estimates made by management, as well as internal control over financial reporting and an unqualified opinion on the evaluating the overall financial statement presentation. We believe that our effectiveness of the Company's internal control over financial reporting.

audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, inall material respects, the financial position of DTE Energy Company and subsidiaries tz-aPt- I Teat& cP Deloitte.

Detroit, Michigan Deloitte &Touche LU' at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years inthe period ended December 31, 2005 March 7,2006 Suite 900, 600 Renaissance Center Detroit Michigan 48243-1704 44

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$8tions t--f o-.E Year Ended December 31 (inMillions, Exceptper ShareAmounts) 2005 2004 2003 Operating Revenues S 9,022 S 7,071 $ 7,005 Operating Expenses Fuel, purchased power and gas 3,530 2,007 2,241 Operation and maintenance 3,793 3,355 3,055 Depreciation, depletion and amortization 869 742 685 Taxes otherthan income 274 312 334 Asset (gains) and losses, net (390) (215) (77) 8,076 6,201 6,238 Operating Income 946 870 767 Other (income) and Deductions Interest expense 519 516 545 Interest income (57) (55) (37)

Other income (68) (81) (110)

Other expenses 55 67 82 449 447 480 Income Before Income Taxes and Minority Interest 497 423 287 Income Tax Provision (Benefit) (Note 7) 202 174 (116)

Minority Interest (281) (212) (91)

Income from Continuing Operations 576 461 494 Income (Loss) from Discontinued Operations, net of tax (Note 3) (36) (30) 54 Cumulative Effect of Accounting Changes, net of tax (Note 2) (3) - (27)

Net Income $ 537 $ 431 S 521 Basic Earnings per Common Share (Note 8)

Income from continuing operations S 3.29 S 2.67 $ 2.95 Discontinued operations (.20) (.17) .33 Cumulative effect of accounting changes (.02) - (.17)

Total $ 3.07 $ 2.50 $ 3.11 Diluted Earnings per Common Share (Note 8)

Income from continuing operations S 327 $ 2.66 $ 2.93 Discontinued operations (20) (.17) .32 Cumulative effect of accounting changes (.02) - (.16)

Total S 3.05 $ 2.49 $ 3.09 Average Common Shares Basic 175 173 168 Diluted 176 173 168 Dividends Declared per Common Share S 2.06 $ 2.06 $ 2.06 See Notes to Consolidated Financial Statements 45

December 31 an Millions) 2005 2004 ASSETS Current Assets Cash and cash equivalents $ 88 $ 56 Restricted cash (Note 1) 122 126 Accounts receivable Customer (less allowance for doubtful accounts of $136 and $129, respectively) 1288 865 Accrued unbilled revenues 458 378 Collateral held by others 286 44 Other 549 354 Inventories Fuel and gas 522 509 Materials and supplies 146 159 Deferred income taxes 257 94 Assets from risk management and trading activities 806 296 Other 160 115 4,682 2,996 Investments Nuclear decommissioning trustfunds 646 590 Other 530 558 1,176 1,148 Property Property, plant and equipment 18,660 18,011 Less accumulated depreciation and depletion (Notes 1and 2) (7,830) 17,520) 10,830 10,491 Other Assets Goodwill 2,057 2,067 Regulatory assets (Note 4) 2074 2,119 Securitized regulatory assets (Note 4) 1,340 1,438 Notes receivable 409 529 Assets from risk management and trading activities 316 125 Prepaid pension assets 186 184 Other 265 200 6,647 6,662 Total Assets $ 23,335 $ 21,297 See Notes to Consolidated Financial Statements 46

0_Consolida'ted St'atement fFnnilP sto December31 (inMillions, Except Shares) 2005 2004 VABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities Accounts payable $ 1,187 $ 892 Accrued interest 115 111 Dividends payable 92 90 Accrued payroll 34 33 Income taxes - 16 Short-term borrowings 943 403 Current portion long-term debt, including capital leases 691 514 Liabilities from risk management and trading activities 1,089 369 Other 769 581 4,920 3,009 Other Liabilities Deferred income taxes 1,396 1,124 Regulatory liabilities (Notes 2 and 4) 715 817 Asset retirement obligations (Note 2) 1,091 916 Unamortized investment tax credit 131 143 Liabilities from risk management and trading activities 527 224 Liabilities from transportation and storage contracts 317 387 Accrued pension liability 284 265 Deferred gains from asset sales 188 414 Minority interest 92 132 Nuclear decommissioning (Notes 2 and 5) 85 77

-Other 740 635 5,566 5,134 Long-Term Debt (net of current portion) (Note 9)

Mortgage bonds, notes and other 5,234 5,673 Securitization bonds 1,295 1,400 Equity-linked securities 175 178 Trust preferred-linked securities 289 289 Capital lease obligations 87 66 7,080 7,606 Commitments and Contingencies (Notes 4,5 and 13)

Shareholders' Equity Common stock, without par value, 400,000,000 shares authorized, 177,814,429 and 174,209,034 shares issue and outstanding, respectively 3,483 3,323 Retained earnings 2,557 2,383 Accumulated other comprehensive loss (271) (158) 5,769 5,548 Total Liabilities and Shareholders' Equity S 23,335 $ 21,297 See Notes to ConsolidatedFinancialStatements 47

DTE E'nergy Comfpanyh . - ....-.

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Year Ended December 31 (inMillions) 2005 2004 2003 Operating Activities Net income $ 537 $ 431 $ 521 Adjustments to reconcile net income to net cash from operating activities:

Depreciation, depletion and amortization 872 744 691 Deferred income taxes 147 129 (220)

Gain on sale of interests in synfuel projects (367) (219) (83)

Gain on sale of ITC and other assets, net (38) (17) (145)

Partners' share of synfuel project losses (318) (223) (78)

Restructuring charges 33 - -

Contributions from synfuel partners 243 141 65 Cumulative effect of accounting changes 3 - 27 Changes inassets and liabilities, exclusive of changes shown separately (Note 1) (111) 9 172 Net cash from operating activities 1,001 995 950 Investing Activities Plant and equipment expenditures - utility (850) (815) (679)

Plant and equipment expenditures - non-utility (215) (89) (72)

Acquisitions, net of cash acquired (50)

Proceeds from sale of interests insynfuel projects 349 221 89 Proceeds from sale of ITC and other assets, net of cash divested 60 104 669 Restricted cash for debt redemptions 4 5 106 Proceeds from sale of nuclear decommissioning trust fund assets 201 254 199 Investment innuclear decommissioning trust funds (235) (287) (231)

Other investments (66) (74) (71)

Net cash from (used for) investing activities (802) (681) 10 Financing Activities Issuance of long-term debt 869 736 527 Redemption of long-term debt (1,266) (759) (1,208)

Short-term borrowings, net 437 33 (44)

Issuance of common stock 172 41 44 Repurchase of common stock (13)

Dividends on common stock (360) (354) (346)

Other (6) (9) (12)

Net cash used for financing activities (167) (312) (1,039)

Net Increase (Decrease) inCash and Cash Equivalents 32 2 (79)

Cash and Cash Equivalents at Beginning of Period 56 54 133 Cash and Cash Equivalents at End of Period $ 88 $ 56 $ 54 See Notes to ConsolidatedFinancialStatements 48

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land Cmprehensive Common Stock Retained Accumulated Other (Dollars inMillions, Shares in7housands) Shares Amounts Earnings Comprehensive Loss Total Balance, December31, 2002 167,462 S 3,052 $ 2,132 S (619) $ 4,565 I 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, December31,2003 168,607 3,109 2,308 (130) 5,287 Net income - - 431 - 431 Issuance of new shares 5,671 223 - - 223 Dividends declared on common stock - - (357) - (357)

Repurchase and retirement of common stock (69) (3) - - (3)

Pension obligations (Note 14) - - - 7 7 Net change in unrealized losses on derivatives, net of tax - - - (15) (15)

Net change in unrealized losses on investments, net of tax - - - (20) (20)

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

Balance, December31, 2004 174,209 3,323 2,383 (158) 5,548 Net income - - 537 - 537 Issuance of new shares 3,686 172 - - 172 Dividends declared on common stock - - (363) - (363)

Repurchase and retirement of common stock (288) (13) (13)

Pension obligations (Note 14) - - - 4 4 Net change in unrealized losses on derivatives, net of tax - - - (106) (106)

Net change inunrealized losses on investments, net of tax - - - (11) (11)

Unearned stock compensation and other 207 1 - - 1 Balance, December 31, 2005 177,814 S 3,483 S 2,557 S (271) S 5,769 The following table displays comprehensive income (loss):

(inMillions) 2005 2004 2003 Net income $ 537 $ 431 $ 521 Other comprehensive income (loss), net of tax:

Pension obligations, net of taxes of $2,$4 and $226 (Notes 4 and 14) 4 7 420 Net unrealized losses on derivatives:

Gains (losses) arising during the period, net of taxes of S(78),S(26) and $8 (145) (49) 16 Amounts reclassified to income, net of taxes of $21, $18 and $- 39 34 1 (106) (15) 17 Net unrealized gains (losses) on investments:

Gains (losses) arising during the period, net of taxes of $(3), $(3) and $28 (6) (5) 52 Amounts reclassified to income, net of taxes of S12), $(8) and $- (5) (15) -

E11) (20) 52 Comprehensive income S 424 $ 403 $ 1,010 See Notes to Consolidated Financial Statements 49

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NOTE 1 - SIGNIFICANT ACCOUNTING of America. These accounting principles require us to use estimates and assumptions that impact reported amounts of assets, liabilities, POLICIES revenues and expenses, and the disclosure of contingent assets Corporate Structure and liabilities. Actual results may differ from our estimates.

DTE Energy owns the following businesses: We reclassified certain prior year balances to match the current year's financial statement presentation.

The Detroit Edison Company (Detroit Edison), an electric utility engaged in the generation, purchase, distribution and sale Revenues of electric energy to approximately 2.2 million customers in southeast Michigan; Revenues from the sale and delivery of electricity, and the sale,

Michigan Consolidated Gas Company (MichCon), a natural gas delivery and storage of natural gas are recognized as services are utility engaged in the purchase, storage, transmission and provided. Detroit Edison and MichCon record revenues for electric distribution and sale of natural gas to approximately 1.3 million and gas provided but unbilled at the end of each month.

customers throughout Michigan; and

Other non-utility subsidiaries engaged in avariety of energy Detroit Edison's accrued revenues include acomponent for the cost related businesses such as synfuels, energy services, natural of power sold that isrecoverable through the Power Supply Cost gas exploration and production, energy marketing and trading, Recovery (PSCR) mechanism. MichCon's accrued revenues include coal transportation and gas storage and transportation. a component for the cost of gas sold that is recoverable through the Gas Cost Recovery (GCR) mechanism. Annual PSCR and GCR Detroit Edison and MichCon are regulated by the Michigan Public proceedings before the MPSC permit Detroit Edison and MichCon Service Commission (MPSC). The Federal Energy Regulatory to recover prudent and reasonable supply costs. Any overcollection Commission (FERC) regulates certain activities of Detroit Edison's or undercollection of costs, including interest, will be reflected in business as well as various other aspects of businesses under DTE future rates. Prior to 2004, Detroit Edison's retail rates were frozen Energy. Inaddition, we are regulated by other federal and state under Public Act (PA) 141. Accordingly, Detroit Edison did not accrue regulatory agencies including the Nuclear Regulatory Commission revenues under the PSCR mechanism prior to 2004. See Note 4.

(NRC), the U.S. Environmental Protection Agency (EPA) and the Michigan Department of Environmental Quality (MDEQ). Non-utility businesses recognize revenues as services are provided and products are delivered. Our Fuel Transportation and Marketing References in this report to "we," 'us," "our" or "Company" are to segment records in revenues net unrealized derivative gains and losses DTE Energy and its subsidiaries, collectively. on energy trading contracts, including those to be physically settled.

Principles of Consolidation Gains from Sale of Interests inSynthetic Fuel Facilities We consolidate all majority owned subsidiaries and investments in Through December 2005, we have sold interests in all of our entities in which we have controlling influence. Non-majority owned synthetic fuel production plants, representing approximately investments are accounted for using the equity method when the 91% of our total production capacity. Proceeds from the sales are company is able to influence the operating policies of the investee. contingent upon production levels, the production qualifying for Non-majority owned investments include investments inlimited liability production tax credits, and the value of such credits. Production companies, partnerships or joint ventures. When we do not influence tax credits are subject to phase-out if domestic crude oil prices reach the operating policies of an investee, the cost method is used. We certain levels. See Note 13 for further discussion. We recognize eliminate all intercompany balances and transactions. gains from the sale of interests in the synfuel facilities as synfuel is produced and sold, and when there is persuasive evidence that For entities that are considered variable interest entities, we apply the sales proceeds have become fixed or determinable and collectibility the provisions of Financial Accounting Standards Board (FASB) isreasonably assured. Until the gain recognition criteria are met, Interpretation No. (FIN) 46-R, Consolidation of Variable Interest gains from selling interests in synfuel facilities are deferred. It is Entities, an Interpretation of Accounting Research Bulletin (ARB) possible that gains will be deferred inthe first, second and/or third No. 51. For a detailed discussion of FIN 46-R, see Note 2. quarters of each year until there is persuasive evidence that no tax credit phase out will occur for the applicable calendar year. This could result inshifting earnings from earlier quarters to later quarters Basis of Presentation of a calendar year. We have recorded pre-tax gains from the sale The accompanying consolidated financial statements are prepared of interests in synthetic fuel facilities totaling $367 million, $219 using accounting principles generally accepted in the United States million and $83 million during 2005, 2004 and 2003, respectively.

50

The gain from the sale of synfuel facilities is comprised of fixed Property, Retirement and Maintenance, and and variable components. The fixed component represents note Depreciation and Depletion payments of principal and interest, is not subject to refund, and is recognized as a gain when earned and collectibility isassured. The Summary of property by classification as of December 31:

variable component isbased on an estimate of tax credits allocated (inMillions) 2005 2004 to our partners, issubject to refund based on the annual oil price Property, Plant and Equipment phase out, and is recognized as again only when the probability of Electric Utility refund isconsidered remote and collectibility isassured. Inthe event that the tax credit isphased-out, we are contractually obligated to Generation $ 7,375 $ 7,100 Distribution - 6,041 5,831 refund to our partners an amount equal to all or a portion of the operating losses funded by our partners. To assess the probability Total Electric Utility 13,416 12,931 of refund, we use valuation and analyst models that calculate the Gas Utility probability of surpassing the estimated lower band of the phase-out Distribution 2,098 2,020 range for the Reference Price of oil for the year. Due to the rise in Storage 237 221 oil prices, there isa possibility that the Reference Price of oil could Other 929 883 reach the threshold at which production tax credits begin to phase out. Total Gas Utility 3,264 3,124 Other Non-utility and Other 1,980 1,956 Comprehensive Income Total Property, Plant and Equipment 18,660 18,011 Less Accumulated Depreciation and Depletion Comprehensive income isthe change in common shareholders' Electric Utility equity during a period from transactions and events from non-owner Generation (3,439) (3,277) sources, including net income. As shown inthe following table, Distribution (2I156) (2,077) amounts recorded to other comprehensive income at December 31, Total Electric Utility (5,595) (5,354) 2005 include: unrealized gains and losses from derivatives Gas Utility accounted for as cash flow hedges, unrealized gains and losses on Distribution (891) (845) available for sale securities and, minimum pension liabilities.

Storage (104) (1001 Net Net Minimum Accumulated Other (481) (448)

Unrealized Unrealized Pension Other Losses on Gains on Liability Comprehensive Total Gas Utility (1,476) (1,393)

(inMillions) Derivatives Investments Adjustment Loss Other Non-utility and Other (759) (773)

Beginning balance $ (100) S 33 s (911 $ (158) Total Accumulated Depreciation Current-period change (106) (11) 4 (113) and Depletion (7,830) (7,520)

Ending balance S (206) S 22 $ 187) S (2711 Net Property, Plant and Equipment $ 10,830 $ 10,491 Cash Equivalents and Restricted Cash Property is stated at cost and includes construction-related labor, materials, overheads and an allowance for funds used during Cash and cash equivalents include cash on hand, cash in banks construction. The cost of properties retired, less salvage, at Detroit and temporary investments purchased with remaining maturities Edison and MichCon is charged to accumulated depreciation.

of three months or less. Restricted cash consists of funds held to satisfy requirements of certain debt and partnership operating Expenditures for maintenance and repairs are charged to expense agreements. Restricted cash isclassified as a current asset as all when incurred, except for Fermi 2.Approximately $25 million of restricted cash isdesignated for interest and principal payments expenses related to the anticipated Fermi 2 refueling outage due within one year. scheduled for 2006 were accrued at December 31, 2005. Amounts are being accrued on a pro-rata basis over an 18-month period that Inventories began in November 2004. We have utilized the accrue-in-advance policy for nuclear refueling outage costs since the Fermi 2 plant We value fuel inventory and materials and supplies at average cost. was placed in service in 1988. This method also matches the Gas inventory at MichCon is determined using the last-in, first-out regulatory recovery of these costs in rates set by the MPSC.

(LIFO) method. At December 31, 2005, the replacement cost of gas We base depreciation provisions for utility property at Detroit remaining instorage exceeded the $119 million LIFO cost by $496 Edison and MichCon on straight-line and units of production rates million. At December 31, 2004, the replacement cost of gas approved by the MPSC. The composite depreciation rate for remaining in storage exceeded the $89 million LIFO cost by $330 Detroit Edison was 3.4% in2005, 2004 and 2003. The composite million. During 2004, MichCon liquidated 5.7 billion cubic feet of depreciation rate for MichCon was 3.2%, 3.6%, and 3.5% in 2005, prior years' LIFO layers. The liquidation benefited 2004 cost of gas 2004 and 2003, respectively.

by approximately $7million, but had no impact on earnings as a result of the GCR mechanism. The average estimated useful life for each class of utility property, plant and equipment as of December 31, 2005 follows:

Our Fuel Transportation and Marketing segment uses the average cost method for its gas ininventory.

51

Estimated Useful Lives in Years Excise and Sales Taxes Utility Generation Distribution Transmission We record the billing of excise and sales taxes as a receivable Electric 39 37 N/A with an offsetting payable to the applicable taxing authority, with Gas N/A 26 30 no impact on the consolidated statement of operations.

Non-utility property isdepreciated over its estimated useful life using straight-line, declining-balance or units-of-production methods. Deferred Debt Costs We credit depreciation, depletion and amortization expense when The costs related to the issuance of long-term debt are deferred we establish regulatory assets for stranded costs related to the and amortized over the life of each debt issue. Inaccordance with electric Customer Choice program and deferred environmental MPSC regulations applicable to our electric and gas utilities, the expenditures. We charge depreciation, depletion and amortization unamortized discount, premium and expense related to debt expense when we amortize the regulatory assets. We credit interest redeemed with a refinancing are amortized over the life of the expense to reflect the accretion income on certain regulatory assets. replacement issue. Discount, premium and expense on early redemptions of debt associated with non-utility operations are charged to earnings.

Gas Production We follow the successful efforts method of accounting for investments Insured and Uninsured Risks in gas properties. Under this method of accounting, all property acquisition costs and costs of exploratory and development wells Our comprehensive insurance program provides coverage for various are capitalized when incurred, pending determination of whether types of risks. Our insurance policies cover risk of loss from property the well has found proved reserves. If an exploratory well has not damage, general liability, workers' compensation, auto liability and found proved reserves, the costs of drilling the well are expensed. directors' and officers' liability. Under our risk management policy, The costs of development wells are capitalized, whether productive we self-insure portions of certain risks up to specified limits, depending or nonproductive. Geological and geophysical costs on exploratory on the type of exposure. We have an actuarially determined estimate prospects and the costs of carrying and retaining unproved properties of our incurred but not reported liability prepared annually and are expensed as incurred. An impairment loss isrecorded to the adjust our reserves for self-insured risks as appropriate.

extent that capitalized costs of unproved properties, on a property-by-property basis, are considered not to be realizable. An impairment Stock-Based Compensation loss isrecorded if the net capitalized costs of proved gas properties We have a stock-based employee compensation plan, which is exceed the aggregate related undiscounted future net revenues. described in Note 15. The plan permits the awarding of various Depreciation, depletion and amortization of proved gas properties stock awards, including options, restricted stock and performance are determined using the units-of-production method. shares. We account for stock awards under the plan under the recognition and measurement principles of Accounting Principles Long-Lived Assets Board (APB) No. 25, Accounting for Stock Issued to Employees, and Our long-lived assets are reviewed for impairment whenever events follow the nominal vesting period approach for awards with retire-or changes incircumstances indicate the carrying amount of an asset ment eligibility provisions. This approach differs from the non-sub-may not be recoverable. If the carrying amount of the asset exceeds stantive vesting period approach required by SFAS 123-R, Share-the expected future cash flows generated by the asset, an impairment Based Payments. Upon adoption of SFAS 123-R, we will apply the loss is recognized resulting in the asset being written down to its non-substantive vesting period approach for recognizing compensa-estimated fair value. Assets to be disposed of are reported at the tion cost for all newly granted awards with retirement eligibility lower of the carrying amount or fair value less cost to sell. provisions. No compensation cost related to stock options is reflect-ed inearnings, as all options granted had an exercise price equal to the market value of the underlying common stock on the date of Intangible Assets, Including Software Costs grant. The recognition provisions under Statement of Financial Our intangible assets consist primarily of software. We capitalize Accounting Standards (SFAS) No. 123, Accounting for Stock-Based the costs associated with computer software we develop or obtain Compensation, require the recording of compensation expense for for use in our business. We amortize intangible assets on a stock options equal to their fair value at date of grant as determined straight-line basis over the expected period of benefit, ranging using an option pricing model. The following table illustrates the from 3 to 30 years. Intangible assets amortization expense was effect on net income and earnings per share if we had recorded

$41 million in 2005, $43 million in 2004 and $40 million in2003. The compensation expense for options granted under the fair value gross carrying amount and accumulated amortization of intangible recognition provisions of SFAS No. 123.

assets at December 31, 2005 were $531 million and $167 million, respectively. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2004 were $445 million and

$151 million, respectively. Amortization expense of intangible assets is estimated to be $46 million annually for 2006 through 2010.

52

(in Millions, except pershare amounts) 2005 2004 2003 Supplementary cash and non-cash information for the years ended Net Income as Reported $ 537 $ 431 $ 521 December 31, were as follows:

Less: Total Stock-based Expense (1) (4) (6) (7)

Pro Forma Net Income S 533 $ 425 $ 514 (inMillions) 2005 2004 2003 Income Per Share Cash Paid for:

Basic - as reported $ 3.07 S 2.50 $ 3.11 Interest (excluding interest Basic - pro forma S 3.05 S 2.46 $ 3.06 capitalized) $s 516 $ 517 $ 552 Diluted - as reported S 3.05 S 2.49 $ 3.09 Income taxes $ 80 $ 203 S 31 Noncash Investing and Diluted - pro forma S 3.03 $ 2.45 S 3.05 Financing Activities (1) Expense determined using a Black-Scholes based option pricing model.

Notes received from sale of synfuel projects $ 20 $ 214 $ 238 Investments in Debt and Equity Securities Common stock contribution to pension plan - $ 170 $

We generally classify investments in debt and equity securities Exchange of debt -$ -$ 100 as either trading or available-for-sale and have recorded such Sale of assets investments at market value with unrealized gains or losses included Note receivable 47 $

in earnings or in other comprehensive income or loss, respectively.

Changes in the fair value of nuclear decommissioning-related Other assets S 45 $

investments are recorded as adjustments to regulatory assets or liabilities. See Note 5. We have entered into a Margin Loan Facility (Facility) with an affiliate of the clearing agent of a commodity exchange in lieu of posting additional cash collateral (anon-cash transaction). The Investment in Plug Power loan outstanding under the Facility was $103 million as of December We own 8.8 million shares of Plug Power Inc. We account for our 31, 2005 and the related margin deposit is included in collateral investment under the cost method of accounting. We record our held by others on the consolidated statement of financial position.

investment at market value and account for unrealized gains and losses See Note 10.

inother comprehensive income or loss. InDecember 2005, we contributed 1.8 million shares of Plug Power to the DTE Energy Foundation that See the following notes for other accounting policies impacting our resulted ina gain of approximately $1million due to related tax effects. financial statements:

InMay 2004, we sold 3.5 million shares of Plug Power stock and recorded again of approximately $14 million (net of taxes). Note Title 2 New Accounting Pronouncements 4 Regulatory Matters Consolidated Statement of Cash Flows 7 Income Taxes 12 Financial and Other Derivative Instruments A detailed analysis of the changes in assets and liabilities that are 14 Retirement Benefits and Trusteed Assets reported inthe consolidated statement of cash flows follows:

(inMillions) 2005 2004 2003 Note 2 - New Accounting Changes inAssets and Liabilities, Exclusive of Changes Shown Separately Pronouncements Accounts receivable, net $ (553)$ 73 $ (50)

Accrued unbilled receivable (62)

Energy Trading Activities (80) (20)

Accrued GCR revenue (16) (35) 29 Under Emerging Issues Task Force (EITF) Issue No. 98-10, Accounting Inventories (6) (40) (61) for Contracts Involved in Energy Trading and Risk Management Accrued/Prepaid pensions 17 88 (196) Activities, companies were required to use mark-to-market accounting Accounts payable 290 266 (21) for contracts utilized inenergy trading activities. EITF Issue No. 98-10 Accrued PSCR refund (127) 112 was rescinded inOctober 2002, and energy trading contracts must Exchange gas payable 5 (43) 90 now be reviewed to determine if they meet the definition of a Income taxes payable (38) (170) 135 derivative under SFAS No. 133, Accounting for Derivative Instruments General taxes (11) (14) (12) andHedgingActivities. SFAS No. 133 requires all derivatives to Risk management and be recognized in the statement of financial position as either trading activities 353 (64) 127 assets or liabilities measured at their fair value. SFAS No. 133 also Postretirement obligation 132 29 112 requires that changes inthe fair value of derivatives be recognized Other assets 52 55 67 inearnings unless specific hedge accounting criteria are met.

Other liabilities (129) (186) (28)

Energy trading contracts not meeting the definition of a derivative are accounted for under settlement accounting, effective October

$ (111) $ 9 $ 172 25, 2002 for new contracts and effective January 1,2003 for existing contracts. Derivative contracts are only marked to market to the extent that markets are considered highly liquid where objective, 53

transparent prices can be obtained. Unrealized gains and losses InJune 2004, we adopted FSP No. 106-2, retroactive to January 1,2004.

are fully reserved for transactions that do not meet the criteria. As a result of the adoption, our accumulated postretirement benefit obligation for the subsidy related to benefits attributed to past service Additionally, inventory utilized in energy trading activities accounted was reduced by approximately $95 million and was accounted for as an for under the fair value method of accounting as prescribed by ARB actuarial gain. The effects of the subsidy reduced net postretirement No. 43 isno longer permitted. Our Fuel Transportation and Marketing costs by $20 million in2005 and $16 million in 2004.

segment uses gas inventory in its trading operations and switched from the fair value method to the average cost method inJanuary 2003. Stock Based Payments Effective January 1,2003, we no longer applied EITF Issue No. 98-10 In December 2004, the FASB issued SFAS No. 123-R, Stock Based to energy contracts and ARB No. 43 to gas inventory. As a result Payments, which established the accounting for transactions in of discontinuing the application of these accounting principles, we which an entity exchanges equity instruments for goods or services.

recorded a cumulative effect of accounting change that reduced SFAS No. 123-R was effective for interim or annual periods beginning net income in2003 by $16 million after-tax. after June 15, 2005 with earlier adoption encouraged. InApril 2005, the U.S. Securities and Exchange Commission delayed the Consolidation of Variable Interest Entities effective date by requiring implementation beginning in the next fiscal year that begins after June 15, 2005. We adopted SFAS No.

InJanuary 2003, FIN 46, Consolidation of Variable Interest Entities, 123-R effective January 1,2006. Based on historical levels of stock an Interpretation of ARB No. 51, was issued and requires an based payments, we estimate that the new standard will reduce investor with a majority of the variable interests (primary beneficiary) net income by approximately $5million to $10 million per year.

in a variable interest entity to consolidate the assets, liabilities and results of operations of the entity. A variable interest entity Asset Retirement Obligations isan entity in which the equity investors do not have controlling interests, the equity investment at risk is insufficient to finance On January 1,2003, we adopted SFAS No. 143, Accounting for the entity's activities without receiving additional subordinated Asset Retirement Obligations, which requires the fair value of an financial support from other parties, or equity investors do not asset retirement obligation be recognized in the period inwhich it share proportionally in gains or losses. isincurred. We identified a legal retirement obligation for the decommissioning costs for our Fermi 1and Fermi 2 nuclear plants.

InOctober 2003 and December 2003, the FASB issued Staff To a lesser extent, we have retirement obligations for our synthetic Position No. FIN 46-6 and FIN 46-Revised (FIN 46-R), respectively, fuel operations, gas production facilities, asphalt plant, gas gather-which clarified and replaced FIN 46 and also provided for the deferral ing facilities and various other operations.

of the effective date of FIN 46 for certain variable interest entities.

We have evaluated all of our equity and non-equity interests and On December 31, 2005, we adopted FASB Interpretation FIN No.

have adopted all current provisions of FIN 46-R. The adoption of 47, Accounting for Conditional Asset Retirement Obligations, an FIN 46-R did not have a material effect on our financial statements. interpretation of FASB Statement No. 143. FIN 47 clarifies that the term conditional asset retirement obligation as used in FASB Medicare Act Accounting Statement No. 143, refers to a legal obligation to perform an asset retirement activity inwhich the timing and/or method of settle-InDecember 2003, the Medicare Prescription Drug, Improvement ment are conditional on a future event. FIN 47 also clarifies that and Modernization Act of 2003 (Medicare Act) was signed into an entity is required to recognize a liability for the fair value of a law. The Medicare Act provides for a non-taxable federal subsidy conditional asset retirement obligation when incurred if fair value to sponsors of retiree health care benefit plans that provide a benefit can be reasonably estimated. The accounting for FIN 47 uses the that isat least "actuarially equivalent" to the benefit established by same methodology as SFAS 143. When a new liability is recorded, law. We elected at that time to defer the provisions of the Medicare an entity will capitalize the costs of the liability by increasing the Act, and its impact on our accumulated postretirement benefit carrying amount of the related long-lived asset. The liability is obligation and net periodic postretirement benefit cost, pending the accreted to its present value each period, and the capitalized cost issuance of specific authoritative accounting guidance by the FASB. isdepreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its InMay 2004, FASB Staff Position (FSP) No. 106-2 was issued on recorded amount or incurs a gain or loss upon settlement.

accounting for the effects of the Medicare Act. The guidance inthis FSP isapplicable to sponsors of single-employer defined benefit As to regulated operations, we believe that adoptions of SFAS No. 143 postretirement health care plans for which (a)the employer has and FIN 47 result primarily in timing differences in the recognition concluded the prescription drug benefits available under the plan of legal asset retirement costs that we are currently recovering in to some or all participants are "actuarially equivalent" to Medicare rates. We will be deferring such differences under SFAS No. 71, Part Dand thus qualify for the subsidy under the Medicare Act and Accounting for the Effects of Certain Types of Regulation.

(b)the expected subsidy will offset or reduce the employer's share of the cost of the underlying postretirement prescription drug coverage As a result of adopting FIN 47 on December 31, 2005, we identified on which the subsidy isbased. We believe we qualify for the subsidy conditional retirement obligations for gas pipeline retirement costs under the Medicare Act and the expected subsidy will partially offset and disposal of asbestos at certain of our power plants. To a lesser our share of the cost of postretirement prescription drug coverage. extent, we have conditional retirement obligations at certain service 54

centers, compressor and gate stations, and PCB disposal costs within Dtech assets are $6million, consisting primarily of receivables transformers and circuit breakers. We recorded a plant asset of $26 and inventory, and liabilities are $6million at December 31, 2005.

million with offsetting accumulated depreciation of $14 million, and an asset retirement obligation liability of $124 million. We also As shown inthe following table, we have reported the business activity recorded acumulative effect amount related to utility operations of Dtech as adiscontinued operation. The amounts include the as a reduction to a regulatory liability of $108 million and acumulative impairment loss recorded in the third quarter of 2005 and exclude effect charge against earnings of $3million, after-tax in 2005. general corporate overhead costs and operations that are to be retained:

If we had applied FIN 47 to prior periods, we would have recorded (inMillions) 2005 2004 2003 asset retirement obligations of $123 million and $121 million as of Revenues11) $ 18 $ 43 $ 36 December 31, 2004 and 2003, respectively, with an immaterial Expenses 67 70 57 effect on earnings. Loss before taxes (49) (27) (21)

Income tax benefit (14) (9) (7)

No liability has been recorded with respect to lead-based paint, as the (Loss)fromdiscontinuedoperations S (35) $ (18) $ (14) quantities of lead-based paint are unknown. Inaddition, there is no 1l Includes intercompany revenues of $6million for 2005 and $5 million for 2004.

incremental cost to demolitions of lead-based paint facilities vs. non-lead based paint facilities and no regulations currently exist requiring Southern Missouri Gas Company - Discontinued any type of special disposal of items containing lead-based paint. Operation Ludington Hydroelectric Power Plant has an indeterminate life and We owned Southern Missouri Gas Company (SMGC), a public utility no legal obligation currently exists to decommission the plant at some engaged in the distribution, transmission and sale of natural gas in future date. Substations, manholes and certain other distribution southern Missouri. Inthe first quarter of 2004, management assets within Detroit Edison have an indeterminate life, therefore, approved the marketing of SMGC for sale. As of March 31, 2004, no liability has been recorded for this asset. SMGC met the SFAS No. 144 criteria of an asset "held for sale" and we reported its operating results as a discontinued operation. We A reconciliation of the asset retirement obligation for 2005 follows: recognized a net of tax impairment loss in 2004 of approximately

$7million, representing the write-down to fair value of the assets (inMillions) of SMGC, less costs to sell, and the write-off of allocated goodwill.

Asset retirement obligations at January 1,2005 $ 916 InNovember 2004, we entered into a definitive agreement providing Accretion 61 for the sale of SMGC. Regulatory approval was received in April Liabilities incurred (primarily adoption of FIN 47) 129 2005 and the sale was closed in May 2005. During the second Liabilities settled (15) quarter of 2005, we recognized a net of tax gain of $2million.

Asset retirement obligations at December 31, 2005 $ 1,091 International Transmission Company - Discontinued A significant portion of the asset retirement obligations represents Operation nuclear decommissioning liabilities which are funded through a InFebruary 2003, we sold International Transmission Company (ITC),

surcharge to electric customers over the life of the Fermi 2nuclear plant.

our electric transmission business, for $610 million to affiliates of Kohlberg Kravis Roberts & Co. and Trimaran Capital Partners, LLC.

Note 3 - Dispositions The sale generated a preliminary net of tax gain of $63 million in 2003. The gain was net of transaction costs, the portion of the gain DTE Energy Technologies (Dtech) - Discontinued that was refundable to customers and the write off of approximately Operation $44 million of allocated goodwill. The gain was lowered to $58 million in2004 under the MPSC's November 2004 final rate order that resulted We own Dtech, which assembles, markets, distributes and services in a revision of the applicable transaction costs and customer refund.

distributed generation products, provides application engineering, During 2005, the net of tax gain was adjusted to $56 million.

and monitors and manages on-site generation system operations. In July 2005, management approved the restructuring of this business We have reported the operations of ITC, from January 1,2003 resulting inthe identification of certain assets and liabilities to be through February 28, 2003, as a discontinued operation as shown sold or abandoned, primarily associated with standby and continuous in the following table:

duty operations. The systems monitoring business and certain other operations are planned to be retained. We anticipate completing (inMillions) 2003 the restructuring plan by mid-2006. Revenues (1) $ 21 Expenses (2) 13 During the third quarter of 2005, the restructuring plan met criteria Operating income 8 to classify the assets as "held for sale." Accordingly, we recognized Income taxes 3 a net of tax restructuring loss of $23 million during the third Income from discontinued operations S 5 quarter of 2005 primarily representing the write down to fair (1)Includes intercompany revenues of $18 million.

value of the assets of Dtech, less costs to sell, and the write-off (2)Excludes general corporate overhead coststhatwere previously alocated to ITc.

of goodwill of $16 million. After the restructuring charge, 55

Detroit Edison's Steam Heating Business (inMillions) 2005 2004 Assets InJanuary 2003, we sold Detroit Edison's steam heating business Securitized regulatory assets $ 1,34 $ 1,438 to Thermal Ventures 11, LP. Due to the continuing involvement of Recoverable income taxes related to Detroit Edison inthe steam heating business, including the securitized regulatory assets $ 734 $ 788 commitment to purchase steam, fund certain capital improvements Recoverable minimum pension liability 544 605 and guarantee the buyer's credit facility, we recorded a net of tax Asset retirement obligation 196 183 loss of approximately $14 million in 2003. As a result of Detroit Other recoverable income taxes 104 109 Edison's continuing involvement, this transaction is not considered Recoverable costs under PA 141 a sale for accounting purposes. See Note 13.

Netstranded costs 112 122 Excess capital expenditures 22 7 Note 4 - Regulatory Matters Deferred Clean Air Act expenditures 82 76 Midwest Independent System Operator charges 56 27 Regulation Electric Customer Choice implementation costs 98 95 Detroit Edison and MichCon are subject to the regulatory jurisdiction Enhanced security costs 13. 8 of the MPSC, which issues orders pertaining to rates, recovery of Unamortized loss on reacquired debt 73 63 certain costs, including the costs of generating facilities and regulatory Deferred environmental costs 34 31 assets, conditions of service, accounting and operating-related Accrued GCR revenue 42 55 matters. Detroit Edison isalso regulated by the FERC with respect Accrued PSCR revenue 144 -

to financing authorization and wholesale electric activities. Recoverable uncollectibles expense 11 -

Other 6 5 As subsequently discussed inthe "Electric Industry Restructuring" 2,271 2,174 section, Detroit Edison's rates were frozen through 2003 and Less amount included in current assets (197) (55) capped for small business customers through 2004 and for residential S 2,074 $ 2,119 customers through 2005 as a result of PA 141. However, Detroit Edison was allowed to defer certain costs to be recovered once Liabilities rates could be increased, including costs incurred as a result of Asset removal costs $ 567 $ 679 changes in taxes, laws and other governmental actions. Accrued pension 23 1 Refundable income taxes 125 135 Regulatory Assets and Liabilities Accrued GCR disallowance - 28 Accrued PSCR refund 129 112 Detroit Edison and MichCon apply the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, to their Other 2 4 regulated operations. SFAS No. 71 requires the recording of regulatory 846 959 assets and liabilities for certain transactions that would have been Less amount included incurrent liabilities (131) (142) treated as revenue and expense in non-regulated businesses. S 715 $ 817 Continued applicability of SFAS No. 71 requires that rates be designed to recover specific costs of providing regulated services Assets and be charged to and collected from customers. Future regulatory changes or changes inthe competitive environment could result in

Securitized regulatory assets -The net book balance of the the Company discontinuing the application of SFAS No. 71 for some Fermi 2 nuclear plant was written off in 1998 and an equivalent or all of its utility businesses and may require the write-off of the regulatory asset was established. In2001, the Fermi 2 regulatory portion of any regulatory asset or liability that was no longer probable asset and certain other regulatory assets were securitized pursuant of recovery through regulated rates. Management believes that to PA 142 and an MPSC order. A non-bypassable securitization currently available facts support the continued application of SFAS bond surcharge recovers the securitized regulatory asset over a No. 71 to Detroit Edison and MichCon. fourteen-year period ending in 2015.

Recoverable income taxes related to securitized regulatory The following are balances and a brief description of the regulatory assets - Receivable for the recovery of income taxes to be paid assets and liabilities at December 31: on the non-bypassable securitization bond surcharge. A non-bypassable securitization tax surcharge recovers the income tax over a fourteen-year period ending 2015.

56

Recoverable minimum pension liability- An additional minimum Liabilities pension liability was recorded under generally accepted accounting principles due to the current under funded status of

Asset removal costs - The amount collected from customers for certain pension plans. The traditional rate setting process allows the funding of future asset removal activities.

for the recovery of pension costs as measured by generally

Accrued pension - Pension expense refundable to customers accepted accounting principles. Accordingly, the minimum pension representing the difference created from volatility in the pension liability associated with utility operations isrecoverable. See obligation and amounts recognized pursuant to MPSC authorization.

Note 14.

Refundable income taxes - Income taxes refundable to

Asset retirement obligation - Asset retirement obligations were MichCon's customers representing the difference in property-recorded pursuant to adoption of SFAS No. 143 in 2003 and related deferred income taxes payable and amounts recognized FIN 47 in 2005. These obligations are primarily for Fermi 2 pursuant to MPSC authorization.

decommissioning costs that are recovered in rates.

Accrued 6CR disallowance - Refund resulting from an MPSC

Other recoverable income taxes - Income taxes receivable order in MichCon's 2002 GCR plan case that required MichCon from Detroit Edison's customers representing the difference in to reduce revenues in the calculation of its 2002 GCR expense.

property-related deferred income taxes receivable and amounts

Accrued PSCR refund- Payable for the temporary over-recovery previously reflected in Detroit Edison's rates. of and a return on power supply costs, and beginning with the

Net stranded costs- PA 141 permits, after MPSC authorization, MPSC's November 2004 rate order, transmission costs incurred by the recovery of and a return on fixed cost deficiency associated Detroit Edison which are recoverable through the PSCR mechanism.

with the electric Customer Choice program. Net stranded costs occur when fixed cost related revenues do not cover the fixed Electric Rate Restructuring Proposal cost revenue requirements. InFebruary 2005, Detroit Edison filed a rate restructuring proposal

Excess capital expenditures - Starting in 2004, PA 141 permits, with the MPSC to restructure its electric rates and begin phasing after MPSC authorization, the recovery of and a return on capital out subsidies within the current pricing structure. InDecember 2005, expenditures that exceed a base level of depreciation expense. the MPSC issued an order that did not provide for the comprehensive

Deferred CleanAirActexpenditures- PA 141 permits, after realignment of the existing rate structure that Detroit Edison requested MPSC authorization, the recovery of and a return on Clean Air in its rate restructuring proposal. The MPSC order did take some Act expenditures. initial steps to improve the current competitive imbalance inMichigan's

Midwest Independent System Operator charges - PA 141 permits, electric Customer Choice program. The December 2005 order after MPSC authorization, the recovery of and a return on establishes cost-based power supply rates for Detroit Edison's full charges from a regional transmission operator such as the service customers. Electric Customer Choice participants will pay Midwest Independent System Operator. cost-based distribution rates, while Detroit Edison's full service

Electric Customer Choice implementation costs - PA 141 permits, commercial and industrial customers will pay cost-based distribution after MPSC authorization, the recovery of and a return on costs rates that reflect the cost of the residential rate subsidy. Residential incurred associated with the implementation of the electric customers continue to pay a subsidized below cost rate for distribution Customer Choice program. service. These revenue neutral revised rates were effective February

Enhancedsecuritycosts- PA 609 of 2002 permits, after MPSC 1,2006. Detroit Edison was also ordered to file a general rate authorization, the recovery of enhanced security costs for an case by July 1,2007, based on 2006 actual results.

electric generating facility.

Unamortizedloss on reacquired debt- The unamortized discount, Other Postretirement Benefits Costs Tracker premium and expense related to debt redeemed with a refinancing InFebruary 2005, Detroit Edison filed an application, pursuant to are deferred, amortized and recovered over the life of the the MPSC's November 2004 final rate order, requesting MPSC replacement issue.

approval of a proposed tracking mechanism for retiree health care

Deferred environmental costs - The MPSC approved the deferral costs. This mechanism would recognize differences between cost and recovery of investigation and remediation costs associated levels collected in rates and the actual costs under current with Gas Utility's former manufactured gas plant (MGP) sites. accounting rules as regulatory assets or regulatory liabilities with

Accrued 6CR revenue - Receivable for the temporary under- an annual reconciliation proceeding before the MPSC. InFebruary recovery of and a return on gas costs incurred by MichCon 2006, the MPSC denied Detroit Edison's request and ordered that which are recoverable through the GCR mechanism. this issue be addressed in the next general rate case due to be

Accrued PSCR revenue - Receivable for the temporary under- filed by July 1,2007.

recovery of and a return on fuel and purchased power costs incurred by Detroit Edison which are recoverable through the 2004 PSCR Reconciliation and 2004 Net Stranded PSCR mechanism.

Cost Case

Recoverable uncollectibles expense - MichCon receivable for the MPSC approved uncollectible expense true-up mechanism Inaccordance with the MPSC's direction in Detroit Edison's that tracks the difference inthe fluctuation inuncollectible accounts November 2004 rate order, in March 2005, Detroit Edison filed a and amounts recognized pursuant to the MPSC authorization. joint application and testimony in its 2004 PSCR Reconciliation Case and its 2004 Net Stranded Cost Recovery Case. The combined 57

proceeding will provide a comprehensive true-up of the 2004 PSCR denied in December 2003. The MPSC's November 2004 order and production fixed cost stranded cost calculations, including authorized recovery of $44 million of historical stranded costs treatment of Detroit Edison's third party wholesale sales revenues. incurred in2002, 2003 and January and February 2004 collectible Under the MPSC's preferred methodology, Detroit Edison incurred from electric Customer Choice customers through transition charges.

approximately $112 million instranded costs for 2004. Detroit From March 2004 through the first quarter of 2005, Detroit Edison Edison also received approximately $218 million in third party recorded $112 million of additional stranded costs as a regulatory wholesale sales. asset as the result of rate caps and higher electric Customer Choice sales losses than included inthe 2004 MPSC interim order. InMarch Inthe filing, Detroit Edison recommended the following distribution of 2005, Detroit Edison filed an application for its 2004 stranded of the $218 million of third party wholesale sale revenues: $91 cost recovery case. A final order isexpected in the first half of 2006.

million to offset PSCR fuel expense and $74 million to offset 2004 production operation and maintenance expense. The remaining Securitization - Detroit Edison formed The Detroit Edison Securitization

$53 million would be allocated between bundled customers and Funding LLC (Securitization LLC), a wholly owned subsidiary, for the electric Customer Choice customers. This allocation would result purpose of securitizing its qualified costs, primarily related to the in a refund of approximately $8million to bundled customers and a unamortized investment inthe Fermi 2 nuclear power plant. InMarch net stranded cost amount to be collected from electric Customer 2001, the Securitization LLC issued $1.75 billion of securitization Choice customers of approximately $99 million. bonds, and Detroit Edison sold $1.75 billion of qualified costs to the Securitization LLC. The Securitization LLC is independent of Included with the application was the filing of a motion for a Detroit Edison, as is its ownership of the qualified costs. Due to temporary interim order requesting the continuation of the existing principles of consolidation, the qualified costs and securitization electric Customer Choice transition charges until a final order is bonds appear on our consolidated statement of financial position.

issued. The MPSC denied this motion inAugust 2005. A final order We make no claim to these assets. Ownership of such assets has is expected in the first half of 2006. vested in the Securitization LLC and been assigned to the trustee for the securitization bonds. Neither the qualified costs nor funds Electric Industry Restructuring from an MPSC approved non-bypassable surcharge collected from Detroit Edison's customers for the payment of costs related to the Electric Rates, Customer Choice and Stranded Costs - In2000, the Securitization LLC and securitization bonds are available to Detroit Michigan Legislature enacted PA 141 that reduced electric retail Edison's creditors.

rates by 5%, as a result of savings derived from the issuance of securitization bonds. The legislation also contained provisions DTE2 Accounting freezing rates through 2003 and preventing rate increases (i.e., rate caps) for small business customers through 2004 and for residential InJuly 2004, Detroit Edison filed an accounting application with

__ s__.H nn~r TL__ __ At _r - la A}------ S ^ ,L- Ano.^ _.._:- - . 1 _s5: rATrv Pal c J .

2006 Plan Year- InSeptember 2005, Detroit Edison filed its 2006 Emergency Rules for Electric and Gas Bills PSCR plan case seeking approval of a levelized PSCR factor of 4.99 mills per kWh above the amount included inbase rates for residential InOctober 2005, the MPSC established emergency billing practices customers and 8.29 per kWh above the amount included in base in effect for electric and gas services rendered November 1,2005 rates for commercial and industrial customers. Included in the through March 31, 2006. These emergency rules apply to retail factor for all customers are power supply costs, transmission electric and gas customers. The rule changes:

expenses, MISO market participation costs, and nitrogen oxide

lengthen the period of time before a bill is due once it is emission allowance costs. The Company's PSCR Plan includes a transmitted to the customer; matrix which provides for different maximum PSCR factors contingent on varying electric Customer Choice sales levels. The plan also

prohibit shut off or late payment fees unless an actual meter includes $97 million for recovery of its projected 2005 PSCR under- read ismade; collection associated with commercial and industrial customers.

limit the required monthly payment on a settlement agreement; Additionally, the PSCR plan requests MPSC approval of expense

increase the income level qualifying for shut-off protection and associated with sulfur dioxide emission allowances, mercury lower the payment required to remain on shut-off protection; and emission allowances, and fuel additives. Inconjunction with DTE

lessen or eliminate certain deposit requirements.

Energy's sale of the transmission assets of ITC in February 2003, the FERC froze ITC's transmission rates through December 2004. In Transmission Proceedings approving the sale, FERC authorized ITC recovery of the difference between the revenue it would have collected and the actual revenue InNovember 2004, a FERC order approved a transmission pricing ITC did collect during the rate freeze period. At December 31, 2005 structure to facilitate seamless trading of electricity between MISO this amount is estimated to be $66 million which isto be included and the PJM Interconnection. The pricing structure eliminates layers in ITC's rates over a five-year period beginning June 1,2006. It is of transmission charges between the two regional transmission expected that this amortization will increase Detroit Edison's organizations. The FERC noted that the new pricing structure may transmission expense in2006 by $7million. As previously discussed, result in transmission owners facing abrupt revenue shifts. To Detroit Edison received rate orders in 2004 that allow for the facilitate the transition to the new pricing structure, the FERC recovery of transmission expenses through the PSCR mechanism. authorized a Seams Elimination Cost Adjustment (SECA), effective from December 2004 through March 2006. Under MISO's filing InDecember 2005, the MPSC issued a temporary order authorizing with the FERC, Detroit Edison's SECA obligation was approximately the Company to begin implementation of maximum quarterly PSCR $2million per month from December 2004 through March 2005 factors on January 1,2006. The quarterly factors reflect adownward and approximately $1million per month from April 2005 through adjustment inthe Company's total power supply costs of approximately March 2006. InDecember 2004, Detroit Edison filed a request for 2%to reflect the potential variability in cost projections. The rehearing with the FERC which states, among other things, that quarterly factors will allow the Company to more closely track the SECA isretroactive ratemaking and isunlawful under the Federal costs of providing electric service to our customers and, because Power Act. FERC has not ruled on Detroit Edison's request for the non-summer factors are well below those ordered for the rehearing. However in February 2005, FERC ordered hearings to summer months, effectively delay the higher power supply costs review the proposed SECA charges. The charges are being collected to the summer months at which time our customers will not be subject to refund. Hearings on this matter are scheduled to conclude experiencing large expenditures for home heating. The MPSC did in late 2006. Under the MPSC's November 2004 final rate order, not adopt the Company's request to recover its projected 2005 transmission expenses are recoverable through the PSCR mechanism.

PSCR under-collection associated with commercial and industrial Therefore, SECA charges, if ultimately imposed, should not have a customers nor did it adopt the Company's request to implement financial impact to Detroit Edison.

contingency factors based upon the Company's increased costs associated with providing electric service to returning electric Gas Rate Case Customer Choice customers. The MPSC deferred both of those Company proposals to the final order on the Company's entire On April 28, 2005, the MPSC issued an order for final rate relief.

2006 PSCR Plan. The MPSC determined that the base rate increase granted to MichCon should be $61 million annually effective April 29, 2005.

This amount isan increase of $26 million over the $35 million in Administrative and General Expenses Report interim rate relief approved in September 2004. The rate increase to the MPSC was based on a 50% debt and 50% equity capital structure and an InOctober 2005, the MPSC ordered Detroit Edison to file a report 11% rate of return on common equity.

on why its administrative and general expenses appear to be higher than levels incurred by Consumers Energy, Michigan's other major The MPSC adopted MichCon's proposed tracking mechanism for electric utility. On February 1,2006, a report was filed that explained uncollectible accounts receivable. Each year, MichCon will file an Detroit Edison's administrative and general expense differences, as application comparing its actual uncollectible expense to its well as its overall cost and rate competitiveness. designated revenue recovery of approximately $37 million. Ninety percent of the difference will be refunded or surcharged after an annual reconciliation proceeding before the MPSC. The MPSC also 59

approved the deferral of the non-capitalized portion of the negative gas resulted in a gas inventory decrement for the 2001 calendar pension expense. MichCon will record a regulatory liability for any year. For this reason, the MPSC ordered MichCon to reduce its gas negative pension costs as determined under generally accepted cost recovery expenses by $26.5 million for purposes of calculating accounting principles. Included as part of the base rate increase, the 2002 GCR factor. We recorded a$26.5 million reserve in 2003 the order provided for $25 million in rates to recover safety and to reflect the impact of this order.

training costs. There isa one-way tracking mechanism that provides for refunding the portion of the $25 million not expended on an MichCon's 2002 GCR reconciliation case was filed with the MPSC annual basis. in February 2003. The Staff and various intervening parties in this proceeding sought to have the MPSC disallow an additional $26 The MPSC order reduced MichCon's depreciation rates, and the million, representing unbilled revenues at December 2001. One party related revenue requirement associated with depreciation expense also proposed the disallowance of half of an $8million payment by $14.5 million and is designed to have no impact on net income. made to settle Enron bankruptcy issues. The other parties to the case recommended that the Enron bankruptcy settlement be The MPSC did not allow the recovery of approximately $25 million addressed in the 2003 GCR reconciliation case. InApril 2005, the of merger interest costs allocated to MichCon that were incurred MPSC issued an order inthe 2002 GCR reconciliation case affirming by DNE Energy as a result of the acquisition of MCN Energy. the order in the 2002 GCR plan case disallowing $26.5 million related to the use of storage gas in2001. The April 2005 order also The MPSC order also resulted in the disallowance of computer disallowed the additional $26 million representing unbilled revenues system and equipment costs and adjustments to environmental at December 2001. We recorded the impact of the disallowance inthe regulatory assets and liabilities. The MPSC disallowed recovery of first quarter of 2005. The MPSC agreed that the $8million related ninety percent of the costs of a computer billing system that was to the Enron issue be addressed inthe 2003 GCR reconciliation case.

in place prior to DTE Energy's acquisition of MCN Energy in 2001.

As a result of the order, MichCon recognized an impairment of 2003 Plan Year- MichCon's 2003 GCR reconciliation case was filed this asset of approximately $42 million in the first quarter of 2005. with the MPSC in February 2004. InMay 2005, the MPSC issued This impairment had a minimal impact on DTE Energy because a an order in the 2003 GCR reconciliation case approving recovery of valuation allowance was established for this asset at the time of the $8million related to the Enron bankruptcy settlement.

the MCN acquisition in 2001. The MPSC disallowed approximately

$6million of certain computer equipment and related depreciation 2004 Plan Year- InSeptember 2003, MichCon filed its 2004 GCR and the recovery of certain internal labor and legal costs related to plan case proposing a maximum GCR factor of $5.36 per Mcf.

remediation of MGP sites of approximately $6million. The MPSC MichCon agreed to switch from a calendar year to an operational ordered an additional $5million charge due to a change in the year as a condition of its settlement inthe 2003 GCR plan case.

allocation of historical MGP sites insurance proceeds. The operational GCR year runs from April to March of the following year. To accomplish the switch, the 2004 GCR plan reflected a Gas Industry Restructuring 15-month transitional period, January 2004 through March 2005.

Under this transition proposal, MichCon filed two reconciliations InDecember 2001, the MPSC approved MichCon's application for pertaining to the transition period; one in June 2004 addressing a voluntary, expanded permanent gas Customer Choice program, January through March 2004, one filed in June 2005 addressing which replaced the experimental program that expired in March the remaining April 2004 through March 2005 period and consoli-2002. The number of customers eligible to participate inthe gas dating the two for purposes of the case. The June 2005 filing Customer Choice program increased over a three-year period. supported the $46 million under-recovery with interest MichCon Effective April 2004, all of MichCon's approximately 1.3 million had accrued for the period ending March 31, 2005. MichCon does customers could elect to participate in the Customer Choice not expect a final order before the third quarter of 2006.

program, thereby purchasing their gas from suppliers other than MichCon. The MPSC also approved the use of deferred accounting 2005-2006 Plan Year- InDecember 2004, MichCon filed its 2005-for the recovery of implementation costs of the gas Customer 2006 GCR plan case proposing a maximum GCR factor of $7.99 per Choice program. Mcf. The plan includes quarterly contingent GCR factors. These contingent factors allow MichCon to increase the maximum GCR Gas Cost Recovery Proceedings factor to compensate for increases in gas market prices, thereby reducing the possibility of a GCR under-recovery. InApril 2005, the 2002 Plan Year- InDecember 2001, the MPSC issued an order that MPSC issued an order recognizing that Michigan law allows permitted MichCon to implement GCR factors up to $3.62 per Mcf MichCon to self-implement its quarterly contingent factors.

for January 2002 billings and up to $4.38 per Mcf for the remainder MichCon self-implemented quarterly contingent GCR factors of of 2002.3The order also allowed MichCon to recognize a regulatory $8.54 per Mcf in July 2005 and $10.09 per Mcf in October 2005.

asset representing the difference between the $4.38 factor and the

$3.62 factor for volumes that were unbilled at December 31, 2001. Inresponse to market price increases inthe fall of 2005, MichCon The regulatory asset was subject to the 2002 GCR reconciliation filed a petition to reopen the record inthe case during September process. InMarch 2003, the MPSC issued an order in MichCon's 2005. MichCon proposed a revised maximum GCR factor of $13.10 2002 GCR plan case. MichCon's decision during 2001 to utilize storage per Mcf and a revised contingent factor matrix. Inits order issued October 6,2005, the MPSC reopened the record in the case.

60

On October 28, 2005, the MPSC approved an increase in the Detroit Edison maintains a policy for extra expenses, including GCR factor to a cap of $11.3851 per Mcf for the period replacement power costs necessitated by Fermi 2's unavailability November 2005 through March 2006. due to an insured event. These policies have a 12-week waiting period and provide an aggregate $490 million of coverage over a 2006-2007 Plan Year- InDecember 2005, MichCon filed its 2006- three-year period.

2007 GCR plan case proposing a maximum GCR Factor of $12.15 per Mcf. The plan includes quarterly contingent GCR factors. Detroit Edison has $500 million in primary coverage and $2.25 billion These contingent factors allow MichCon to increase the maximum of excess coverage for stabilization, decontamination, debris removal, GCR factor to compensate for increases in market prices, thereby repair and/or replacement of property and decommissioning. The reducing the possibility of a GCR under-recovery. combined coverage limit for total property damage is $2.75 billion.

Minimum Pension Liability For multiple terrorism losses caused by acts of terrorism not covered under the Terrorism Risk Insurance Extension Act of 2005 (TRIA)

InDecember 2002, we recorded an additional minimum pension occurring within one year after the first loss from terrorism, the liability as required under SFAS No. 87, with offsetting amounts to NEIL policies would make available to all insured entities up to an intangible asset and other comprehensive income. During 2003, $3.2 billion, plus any amounts recovered from reinsurance, government the MPSC Staff provided an opinion that the MPSC's traditional indemnity, or other sources to cover losses.

rate setting process allowed for the recovery of pension costs as measured by SFAS No. 87. Based on the MPSC Staff opinion, Under the NEIL policies, Detroit Edison could be liable for maximum management believes that it will be allowed to recover in rates assessments of up to approximately $30 million per event if the the minimum pension liability associated with its utility operations loss associated with any one event at any nuclear plant inthe United and as such the amount was reclassified to a regulatory asset. States should exceed the accumulated funds available to NEIL.

At December 31, 2005 and 2004, we have recorded a regulatory asset of approximately $544 million ($354 million net of tax) and Public Liability Insurance

$605 million ($393 million net of tax), respectively. See Note 14.

As required by federal law, Detroit Edison maintains $300 million Other of public liability insurance for a nuclear incident. For liabilities arising from a terrorist act outside the scope of TRIA, the policy is We are unable to predict the outcome of the regulatory matters subject to one industry aggregate limit of $300 million. Further, discussed herein. Resolution of these matters isdependent upon under the Price-Anderson Amendments Act of 2005, deferred future MPSC orders and appeals, which may materially impact the premium charges up to $101 million could be levied against each financial position, results of operations and cash flows of the Company. licensed nuclear facility, but not more than $15 million per year per facility. Thus, deferred premium charges could be levied against all owners of licensed nuclear facilities inthe event of a nuclear Note 5 - Nuclear Operations incident at any of these facilities.

General Decommissioning Fermi 2,our nuclear generating plant, began commercial operation in 1988. Fermi 2 has a design electrical rating (net) of 1,150 Detroit Edison has a legal obligation to decommission its nuclear megawatts. This plant represents approximately 10% of Detroit power plants following the expiration of their operating licenses.

Edison's summer net rated capability. The net book balance of the This obligation isreflected as an asset retirement obligation, Fermi 2 plant was written off at December 31, 1998, and an equivalent which isclassified as a noncurrent regulatory liability. Based on regulatory asset was established. In2001, the Fermi 2 regulatory the actual or anticipated extended life of the nuclear plant, asset was securitized. See Note 4.Detroit Edison also owns Fermi decommissioning expenditures for Fermi 2are expected to be 1,a nuclear plant that was shut down in 1972 and is currently incurred primarily during the period 2025 through 2041. It is being decommissioned. The NRC has jurisdiction over the licensing estimated that the cost of decommissioning Fermi 2,when its and operation of Fermi 2 and the decommissioning of Fermi 1. license expires in 2025, will be $1.1 billion in 2005 dollars and

$3.4 billion in 2025 dollars, using a 6%inflation rate. In2001, Detroit Edison began the decommissioning of Fermi 1,with the Property Insurance goal of removing the radioactive material and terminating the Detroit Edison maintains several different types of property Fermi 1 license. The decommissioning of Fermi 1 isexpected to insurance policies specifically for the Fermi 2 plant. These policies be complete by 2010.

cover such items as replacement power and property damage. The Nuclear Electric Insurance Limited (NEIL) isthe primary supplier of Detroit Edison currently recovers funds for decommissioning and the insurance polices. the disposal of low-level radioactive waste through a revenue surcharge. The amounts recovered from customers are deposited in the restricted external trust accounts to fund decommissioning.

61

(in Millions) 2005 2004 2003 Note 6 - Jointly Owned Utility Plant Revenue $ 40 $ 38 $ 36

- 17 62 Detroit Edison has joint ownership interest in two power plants, Net unrealized investment gains Belle River and Ludington Hydroelectric Pumped Storage.

Ownership information of the two utility plants as of December 31, The nuclear decommissioning cost will be funded by investments 2005 was as follows:

held in trust funds that have been established for each nuclear Ludington station. Nuclear decommissioning trust funds are as follows: Hydroelectric Belle Pumped (inMillions) As of December 31 River Storage 2005 2004 In-service date 1984-1985 1973

$ 501 $ 546 Total plant capacity 1,026 MW 1,872 MW Fermi 2 Fermil1 18 18 Ownership interest

49 %

Low level radioactive waste 27 26 Investment (inMillions) $ 1,571 $ 167 Accumulated depreciation (in Millions) $ 778 $ 92 Total S 646 $ 590

DetroitEdison's ownership interestis 63% inUnit No. 1,81% of thefacilities applicableto Belle River used jointly by the Belle River and St Clair Power Plants and 75% incommon At December 31, 2005, investments inthe external trust consisted facilies used at Unit No. 2.

of approximately 49% in publicly traded equity securities, 44% in fixed debt instruments and 7% in cash equivalents. Belle River The NRC has jurisdiction over the decommissioning of nuclear The Michigan Public Power Agency (MPPA) has an ownership power plants and requires decommissioning funding based upon a interest in Belle River Unit No. 1 and other related facilities. The formula. The MPSC and FERC regulate the recovery of costs of MPPA is entitled to 19% of the total capacity and energy of the decommissioning nuclear power plants and both require the use of plant and is responsible for the same percentage of the plant's external trust funds to finance the decommissioning of Fermi 2. operation, maintenance and capital improvement costs.

Rates approved by the MPSC provide for the recovery of decom-missioning costs of Fermi 2. Detroit Edison is continuing to fund Ludington Hydroelectric Pumped Storage FERC jurisdictional amounts for decommissioning even though explicit Consumers Energy Company has an ownership interest in the provisions are not included in FERC rates. We believe the MPSC Ludington Hydroelectric Pumped Storage Plant. Consumers Energy and FERC collections will be adequate to fund the estimated cost is entitled to 51 % of the total capacity and energy of the plant and of decommissioning using the NRC formula. The decommissioning is responsible for the same percentage of the plant's operation, assets, anticipated earnings thereon and future revenues from maintenance and capital improvement costs.

decommissioning collections will be used to decommission the nuclear facilities. We expect the regulatory liabilities to be reduced to zero at the conclusion of the decommissioning activities. If Note 7 - IncomeTaxes amounts remain in the trust funds for these units following the completion of the decommissioning activities, those amounts will We file a consolidated federal income tax return.

be returned to the ratepayers.

Total income tax expense (benefit) varied from the statutory federal income tax rate for the following reasons:

Nuclear Fuel Disposal Costs In accordance with the Federal Nuclear Waste Policy Act of 1982, (Dollars inMillions) 2005 2004 2003 Detroit Edison has a contract with the U.S. Department of Energy Income before income taxes (DOE) for the future storage and disposal of spent nuclear fuel and minority interest S 497 $ 423 $ 287 from Fermi 2. Detroit Edison is obligated to pay the DOE a fee of Less minority interest (281) (212) (91) 1 mill per kWh of Fermi 2 electricity generated and sold. The fee Income from continuing is a component of nuclear fuel expense. Delays have occurred in operations before tax S 778 $ 635 $ 378 the DOE's program for the acceptance and disposal of spent nuclear Income tax expense at fuel at a permanent repository. Until the DOE is able to fulfill its 35% statutory rate $ 272 $ 222 $ 132 obligation under the contract, Detroit Edison is responsible for the Production tax credits (55) (38) (241) spent nuclear fuel storage. Detroit Edison estimates that existing Investment tax credits (8) (8) (8) storage capacity will be sufficient until 2007. We plan expansion Depreciation (4) (4) (4) of our spent fuel storage capacity that will meet our requirements Employee Stock Ownership through 2010. Detroit Edison is a party in the litigation against the Plan dividends (5) (5) (5)

DOE for both past and future costs associated with the DOE's Medicare part Dexempt income (7) (5) -

failure to accept spent nuclear fuel under the timetable set forth in Other, net 9 12 10 the Federal Nuclear Waste Policy Act of 1982. Income tax expense (benefit) from continuing operations $ 202 $ 174 $ (116)

Effective federal income tax rate 25.9 % 27.4 % (30.7)%

62

The minority interest allocation reflects the adjustment to earnings (inMillions) 2005 2004 to allocate partnership losses to third party owners. The tax impact Property $ (1.234) $ (1,193) of partnership earnings and losses are attributable to the partners Securitized regulatory assets (723) (1778) instead of the partnerships. The minority interest allocation is Alternative minimum tax credit carryforward 484 483 therefore removed in computing income taxes associated with Merger basis differences 115 125 continuing operations. Pension and benefits 15 (56)

Net operating loss 56 71 Components of income tax expense (benefit) were as follows: Other 148 317 (inMillions) 2005 2004 2003 $ (1,139) $ (1,031)

Continuing Operations Deferred income tax liabilities $ (2635) $ (2,527)

Current federal and other Deferred income tax assets 1,496 1,496 income tax expense $ 57 $ 40 $ 21 $ (1,139) $ (1,031)

Deferred federal income tax expense (benefit) 145 134 (137) The above table excludes deferred tax liabilities associated with 202 174 (116) unamortized investment tax credits which are shown separately on Discontinued operations (13) (13) 54 the consolidated statement of financial position.

Cumulative Effect of Accounting Changes (2) - (15) During 2005, the IRS completed and closed its audits of our federal Total S 187 $ 161 (77) income tax returns for the years 1998 through 2001. The IRS is currently conducting audits of our federal income tax returns for Production tax credits are provided for qualified fuels produced and the years 2002 and 2003. The Company accrues tax and interest sold by a taxpayer to an unrelated party during the taxable year. related to tax uncertainties that arise due to actual or potential Production tax credits earned but not utilized totaled $484 million disagreements with governmental agencies about the tax treatment and are carried forward indefinitely as alternative minimum tax of specific items. At December 31, 2005, the Company had accrued credits. The majority of the production tax credits earned, including approximately $38 million for such uncertainties. We believe that all of those from our synfuel projects, were generated from projects our accrued tax liabilities are adequate for all years.

that have received a private letter ruling (PLR) from the Internal Revenue Service (IRS). These PLRs provide assurance as to the appropriateness of using these credits to offset taxable income, Note 8 - Common Stock and however, these tax credits are subject to IRS audit and adjustment. Earnings Per Share We have a net operating loss carry-forward of $160 million that expires Common Stock in years 2019 through 2020. We do not believe that avaluation InAugust 2005, we successfully remarketed the senior notes allowance isrequired, as we expect to utilize the loss carry-forward comprising part of our Equity Security Units that were issued in prior to its expiration. June 2002. We also settled the stock purchase contract component of the Equity Security Units by issuing 3.7 million shares of common Deferred tax assets and liabilities are recognized for the estimated stock to holders of these units in August 2005 at an issue price of future tax effect of temporary differences between the tax basis of $46.79. The issue price was calculated by using the average closing assets or liabilities and the reported amounts in the financial price per share of our common stock during a20 trading-day period statements. Deferred tax assets and liabilities are classified as ending August 11, 2005.

current or noncurrent according to the classification of the related assets or liabilities. Deferred tax assets and liabilities not related InMarch 2004, we issued 4,344,492 shares of DTE Energy common to assets or liabilities are classified according to the expected stock, valued at $170 million. The common stock was contributed reversal date of the temporary differences. to a defined benefit retirement plan.

Deferred tax assets (liabilities) were comprised of the following at Under the DTE Energy Company Long-Term Incentive Plan, we grant December 31: non-vested stock awards to key employees, primarily management.

At the time of grant, we record the fair value of the non-vested awards as unearned compensation, which isreflected as areduction incommon stock. The number of non-vested stock awards isincluded inthe number of common shares outstanding; however, for purposes of computing basic earnings per share, non-vested stock awards are excluded.

Shareholders' Rights Agreement We have a Shareholders' Rights Agreement designed to maximize shareholder value should DTE Energy be acquired. Under certain 63

triggering events, each right entitles the holder to purchase from (inMillions) - 2005 (1) 2004 DTE Energy one one-hundredth of a share of Series A Junior DTE Energy Debt Unsecured Participating Preferred Stock of DTE Energy at a price of $90, 6.7% due 2006 to 2033 $ 1,696 $ 1,945 subject to adjustment as provided for inthe Shareholders' Rights Detroit Edison Taxable Debt Principally Secured Agreement. The rights expire in October 2007. 5.8% due 2010 to 2037 2,030 1,672 Detroit Edison Tax Exempt Revenue Bonds (2)

Earnings per Share 5.3%due2008to2032 1,145 1,145 MichCon Taxable Debt Principally Secured We report both basic and diluted earnings per share. Basic earnings 6.2% due 2006 to 2033 785 785 per share iscomputed by dividing income from continuing operations Quarterly Income Debt Securities (QUIDS) - 385 by the weighted average number of common shares outstanding Other Long-Tern Debt Including Non-Recourse Debt 155 151 during the period. Diluted earnings per share assumes the issuance 5,811 6,083 of potentially dilutive common shares outstanding during the period Less amount due within one year (577) (410) and the repurchase of common shares that would have occurred with proceeds from the assumed issuance. Diluted earnings per $ 5234 $ 5,673 share assume the exercise of stock options, vesting of non-vested Securitization Bonds $ 1,400 $ 1,496 stock awards, and the issuance of performance share awards. A Less amount due within one year (105) (96) reconciliation of both calculations is presented inthe following table: S 1,295 $ 1,400 Equity-Linked Securities' S 175 $ 178 (inMillions, except pershare amounts) 2005 2004 2003 Basic Earnings per Share Trust Preferred - Linked Securities Income from continuing operations $ 576.5 $ 460.5 $ 494.0 7.8% due 2032 $ 186 $ 186 Average number of common 7.5% due 2044: 103 103 shares outstanding 175.0 172.6 167.7 $ 289$ 289 Income per share of common Ill Weighted average interest rates as of December 31,2005 stock based on average number (2)Detroit Edison Tax Exempt Revenue Bonds are issued by a public body that loans the of shares outstanding S 3.29 $ 2.67 $ 2.95 proceeds to Detroit Edison on terms substantially mirroring the Revenue Bonds Diluted Earnings per Share Income from continuing operabons S 576.5 $ 460.5 $ 494.0 Debt Issuances Average number of common shares outstanding 175.0 172.6 167.7 In2005, we issued the following long-term debt:

Incremental shares from stock-based awards 1.1 .7 .6 (inMillions)

Month Interest Average number of dilutive Company Issued Type Rate Maturity Amount shares outstanding 176.1 173.3 168.3 Detroit Edison February Senior Notes (1) 4.80% February 2015 $200 Income per share of common DetroitEdison February SeniorNotes(1) 5.45% February2035 200 stock assuming issuance of Detroit Edison August Tax Exempt incremental shares S 3.27 $ 266 $ 2.93 RevenueBonds(2) variable August2029 119 DTE PetCoke September Taxable Bonds variable January 2025 10 Options to purchase approximately two million shares of common stock Detroit Edison September' Senior Notes 13) 5.19% October 2023 100 Detroit Edison October Senior Notes (4) 5.70% October 2037 250 in2005, one million shares in2004 and five million shares in2003 were - ' ' -' ' '. Total Issuances S879 not included inthe computation of diluted earnings per share because (1)The proceeds from the issuance were used to redeem QUIDS of Detroit Edison the options' exercise price was greater than the average market (2\ The proceeds from the issuance were used to refinance Tax Exempt Revenue Bonds of price of the common shares, thus making these options anti-dilutive. Detroit Edison (3)The proceeds from the issuance were used to redeem Senior Notes of Detroit Edison (4)The proceeds from the issuance were used to repay shorttern borrowings of Detroit Edison Note 9 - Long-term Debt and We acquired $15 million in'various notes inconnection with Preferred Securities acquisitions during 2005.

Long-Term Debt Our long-term debt outstanding and weighted average interest rates of debt outstanding at December 31 were:

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Debt Retirements and Redemptions component of its Equity Security Units by issuing common stock to holders of these units. The issue price determined by the average The following debt was retired, through optional redemption or closing price per share of our common stock during a 20 trading-day payment at maturity, during 2005. period ending August 11, 2005 was $46.79 per share. Settlement (in Millions) of the purchase contracts resulted in DTE Energy issuing Month Interest approximately 3.7 million shares of common stock in exchange Company Retired Type Rate Maturity Amount for approximately $172 million.

Detroit Edison February Senior Notes 7.500% February 2005 S 76 Detroit Edison February Remarketed 7.000% August2034 100 Senior Notes Trust Preferred-Linked Securities Detroit Edison March QUIDS (1) 7.625% March 2026 185 DTE Energy has interests in various unconsolidated trusts that Detroit Edison March QUIDS (1) 7.540% June 2028 100 were formed for the sole purpose of issuing preferred securities Detroit Edison March QUIDS (1) 7.375% December2O28 100 and lending the gross proceeds to us. The sole assets of the trusts Detroit Edison September Tax Exempt 6.400% September2O25 97 Revenue are debt securities of DTE Energy with terms similar to those of the Bond 12) related preferred securities. Payments we make are used by the trusts Detroit Edison September Tax Exempt 6.200% August 2025 22 to make cash distributions on the preferred securities it has issued.

Revenue Bond 12)

We have the right to extend interest payment periods on the debt DTE Energy September Senior Notes Variable June 2007 250 Detroit Edison October Senior Notes 131 5.050% October 2005 200 securities. Should we exercise this right, we cannot declare or pay Total Retirement $1,130 dividends on, or redeem, purchase or acquire, any of our capital (1)The QUIDS were redeemed with the proceeds from issuance of Senior Notes by stock during the deferral period.

Detroit Edison (2)These Tax Exempt Revenue Bonds were redeemed with the proceeds from issuance of DTE Energy has issued certain guarantees with respect to payments new Detroit Edison Tax Exempt Revenue Bonds 43)These Senior Notes were paid at maturity with the proceeds from the issuance of on the preferred securities. These guarantees, when taken together Senior Notes by Detroit Edison and short-term borrowings with our obligations under the debt securities and related indenture, provide full and unconditional guarantees of the trusts' obligations The following table shows the scheduled debt maturities, under the preferred securities.

excluding any unamortized discount or premium on debt:

Financing costs for these issuances were paid for and deferred by (in Millions) 2011 and DTE Energy. These costs are being amortized using the straight-line 2006 2007 2008 2009 2010 thereafter Total method over the estimated lives of the related securities.

Amount to mature $682 $352 $457 $363 $681 $5,150 $7,685 Cross Default Provisions Remarketable Securities Substantially all of the net utility properties of Detroit Edison and At December 31, 2004, $175 million of notes of Detroit Edison and MichCon are subject to the lien of mortgages. Should Detroit MichCon were subject to periodic remarketings. The $100 million Edison or MichCon fail to timely pay their indebtedness under scheduled to remarket in February 2005 was optionally redeemed these mortgages, such failure may create cross defaults in the by Detroit Edison, and we do not expect any remarketings to take indebtedness of DTE Energy.

place in2006. We direct the remarketing agents to remarket these securities at the lowest interest rate necessary to produce a Preferred and Preference Securities - Authorized par bid. Inthe event that a remarketing fails, we would be and Unissued required to purchase the securities.

As of December 31, 2005, the amount of authorized and unissued Quarterly Income Debt Securities (QUIDS) stock isas follows:

Detroit Edison had three series of QUIDS outstanding at December Company Type of Stock Par Value Shares Authorized 31, 2004. Detroit Edison redeemed all of its outstanding QUIDS on DTE Energy Preferred (1) None 5,000,000 March 4,2005. Detroit Edison Preferred S 100 6,750,000 Detroit Edison Preference $1 30,000,000 Equity-Linked Securities MichCon Preferred $1 7,000,000 MichCon Preference S1 4,000,000 InJune 2002, DTE Energy issued $173 million of 8.75% Equity Security (1)1.5million shares are reserved for issuance under the Shareholders Units, with each unit consisting of a stock purchase contract and a Rights Agreement senior note of DTE Energy. InAugust 2005, DTE Energy successfully remarketed $172 million aggregate principal amount of its 5.63% Note 10 - Short-term Credit Senior Notes due August 16, 2007 that were originally issued as a Arrangements and Borrowings component of the 8.75% Equity Security Units. Additionally, in August 2005, DTE Energy settled the stock purchase contract DTE Energy and its wholly-owned subsidiaries, Detroit Edison and MichCon, have entered into revolving credit facilities with similar 65

terms. The five-year credit facilities are with a syndicate of banks Detroit Edison has a $200 million short-term financing agreement and may be used for general corporate borrowings, but are intended secured by customer accounts receivable. This agreement contains to provide liquidity support for each of the Companies' commercial certain covenants related to the delinquency of accounts receivable.

paper programs. Detroit Edison iscurrently incompliance with these covenants. We had no balances outstanding under this financing agreement at InOctober 2005, DTE Energy, Detroit Edison and MichCon entered December 31, 2005 and 2004.

into new five-year revolving credit agreements with an aggregate capacity of $925 million. Simultaneously, we amended our existing The weighted average interest rates for short-term borrowings

$975 million, five-year revolving credit facilities to provide for were 4.4% and 2.4% at December 31, 2005 and 2004, respectively.

the substitution of some of the participating lenders, as well as modifications to pricing, conditions to borrowing, covenants, events of default and other miscellaneous provisions to conform to the Note 11 - Capital and Operating Leases terms of the new agreements. The aggregate availability under these Lessee - We lease various assets under capital and operating leases, combined facilities is $1.9 billion as shown inthe following table: including coal cars, agas storage field, office buildings, a warehouse, computers, vehicles and other equipment. The lease arrangements (inMillions) DTE Energy Detroit Edison MichCon Total expire at various dates through 2029.

Five-year unsecured revolving facility, Future minimum lease payments under non-cancelable leases at datedOctober2005 $ 675 $ 69 $ 181 $ 925 December 31, 2005 were:

Five-year unsecured revolving facility, Capital Operating dated October2004 525 206 244 975 (inMillions) Leases Leases Aggregate 2006 $ 16 63 availability S 1200 S 275 S 425 S 1,900 2007 13 51 2008 15 42 Borrowings under the facilities are available at prevailing short-term 2009 15 35 interest rates. The agreements require each of the companies to 2010 13 29 maintain a debt to total capitalization ratio of no more than .65 to 1.

Thereafter 52 316 Should either Detroit Edison or MichCon have delinquent debt obligations of at least $50 million to any creditor, such delinquency Total minimum lease payments 124 $ 536 will be considered a default under DTE Energy's credit agreements. Less imputed interest (26)

DTE Energy, Detroit Edison and MichCon are currently in compliance Presentvalue of net minimum lease payments 98 with these financial covenants. As of December 31, 2005, we had Less current portion (11) outstanding commercial paper of $841 million. Inaddition, we had Non-current portion $ 87 approximately $284 million of letters of credit outstanding against these facilities at December 31, 2005. Rental expense for operating leases was $77 million in 2005, $75 million in 2004 and $73 million in 2003.

In December 2005, DTE Energy entered into a new $150 million letter of credit and reimbursement agreement. The reimbursement Lessor - MichCon leases aportion of its pipeline system to the agreement has a one-year term with avariable interest rate. Vector Pipeline Partnership through acapital lease contract that Provisions for an automatic one-year extension and conversion to a expires in 2020, with renewal options extending for five years.

two-year term loan are available as long as certain conditions are The components of the net investment inthe capital lease at met. We had approximately $80 million of letters of credit outstanding December 31, 2005, were as follows:

against this agreement at December 31, 2005.

(inMillions)

Inconjunction with maintaining certain exchange traded risk 2006 $ 9 management positions, we may be required to post cash collateral 2007 9 with our clearing agent. We have entered into a Margin Loan 2008 9 Facility (Facility) with an affiliate of the clearing agent of up to 2009 9

$103 million as of December 31, 2005. We entered into this facility 2010 9 in lieu of posting cash. This facility was backed by a letter of credit Thereafter 89 issued by DTE Energy in the amount of $100 million. Any margin Total minimum future lease receipts 134 requirement in excess of the Facility isfunded in cash by DTE Residual value of leased pipeline 40 Energy. The amount outstanding under the Facility is subject to an Less unearned income (93) interest rate at a per annum rate of interest equal to the LIBOR Net investment incapital lease 81 rate, plus 0.75%, calculated daily. The amount outstanding under Less current portion (1) the Facility was $103 million and $23 million as of December 31,

$ 80 2005 and 2004, respectively.

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Note 12 - Financial and Other Commodity price risk associated with our utilities is limited due to the PSCR and GCR mechanisms. See Note 1.

Derivative Instruments We comply with SFAS No. 133, Accounting for Derivative Non-Utility Operations Instruments and Hedging Activities, as amended by SFAS No. 138 Fuel Transportation and Marketing - DTE Energy Trading markets and SFAS No. 149. Listed below are important SFAS No. 133 and trades wholesale electricity and natural gas physical products, requirements: trades financial instruments, and provides risk management services utilizing energy commodity derivative instruments. Forwards, futures,

Derivative instruments must be recognized as assets or liabilities options and swap agreements are used to manage exposure to the and measured at fair value, unless they meet the normal risk of market price and volume fluctuations on its operations. These purchases and sales exemption.

derivatives are accounted for by recording changes infair value to

Accounting for changes in fair value depends on the purpose of earnings, usually as adjustments to operating revenues or fuel, the derivative instrument and whether it isdesignated as a purchased power and gas expense. This fair value accounting hedge and qualifies for hedge accounting. better aligns financial reporting with the way the business is

Special accounting isallowed for a derivative instrument qualifying managed and its performance measured.

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

losses are immediately recorded to earnings.

Special accounting isallowed for derivative instruments that Power and Industrial Projects - The Coal-Based Fuels and Landfill qualifying as ahedge and designated as a hedge of the changes Gas Recovery businesses generate production tax credits. We have in fair value of an existing asset, liability or firm commitment. sold interests in all nine of our synthetic fuel production plants.

Gain or loss on the hedging instrument is recorded into earnings. Proceeds from the sales are contingent upon production levels, the An offsetting loss or gain on the underlying asset, liability or production qualifying for production tax credits, and the value of firm commitment isalso recorded to earnings. such credits. Production tax credits are subject to phase out if domestic crude oil prices reach certain levels. See Note 13.

Our primary market risk exposure is associated with commodity prices, credit, interest rates and foreign currency. We have risk To manage our exposure in 2006 and 2007 to the risk of an increase management policies to monitor and decrease market risks. in oil prices that could reduce or eliminate synfuel sales proceeds, We use derivative instruments to manage some of the exposure. we entered into a series of derivative contracts covering a specified Except for the activities of the Fuel Transportation and Marketing number of barrels of oil. The derivative contracts involve purchased segment, we do not hold or issue derivative instruments for trading and written call options that provide for net cash settlement at purposes. The fair value of all derivatives is shown as "assets or expiration based on the full years' 2006 and 2007 average New liabilities from risk management and trading activities" in the York Mercantile Exchange (NYMEX) trading prices for light, sweet consolidated statement of financial position. crude oil in relation to the strike prices of each option. If the average NYMEX prices of oil in 2006 and 2007 are less than approximately Commodity Price Risk $58, and $60, per barrel, respectively, the derivatives will yield no payment. If the average NYMEX prices of oil exceed approximately Utility Operations $58, and $60, per barrel, respectively, the derivatives will yield a payment equal to the excess of the average NYMEX price over these Detroit Edison - Detroit Edison generates, purchases, distributes initial strike prices, multiplied by the number of barrels covered, up and sells electricity. Detroit Edison uses forward energy, capacity, to a maximum price of approximately $73, and $71 per barrel, and futures contracts to manage changes in the price of electricity respectively. The agreements do not qualify for hedge accounting.

and fuel. These derivatives are designated as cash flow hedges or Consequently, changes inthe fair value of the options are recorded meet the normal purchases and sales exemption and are therefore currently in earnings. For all synfuel hedge contracts, including 2005 accounted for under the accrual method. There were no commodity hedges, we recorded total pretax mark to market gains of $48 million price risk cash flow hedges for utility operations at December 31, 2005. in 2005. The fair value changes are recorded as adjustments to the gain from selling interests in synfuel facilities and therefore included MichCon - MichCon purchases, stores, transmits and distributes and inthe 'Asset gains and losses, net" line item inthe consolidated sells natural gas. MichCon has fixed-priced contracts for portions statement of operations.

of its expected gas supply requirements through 2008. These gas supply and firm transportation contracts are designated and qualify Unconventional Gas Production - Our Unconventional Gas business for the normal purchases and sales exemption and are therefore isengaged in natural gas exploration, development and production.

accounted for under the accrual method.

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We use derivative contracts to manage changes inthe price of Note 13 - Commitments and natural gas. These derivatives are designated as cash flow hedges and are primarily legacy transactions. Amounts recorded inother Contingencies comprehensive loss will be reclassified to earnings as the related Synthetic Fuel Operations production affects earnings through 2013. In2005, $35 million of after-tax losses were reclassified to earnings. We partially own nine synthetic fuel production facilities. Synfuel facilities chemically change coal, including waste and marginal Credit Risk coal, into a synthetic fuel as determined under applicable IRS rules. Production tax credits are provided for the production and Our utility and non-utility businesses are exposed to credit risk if sale of solid synthetic fuels produced from coal. To qualify for the customers or counterparties do not comply with their contractual production tax credits, the synthetic fuel must meet three primary obligations. We maintain credit policies that significantly minimize conditions: (1)there must be a significant chemical change in the overall credit risk. These policies include an evaluation of potential coal feedstock, (2)the product must be sold to an unaffiliated entity, customers' and counterparties' financial condition, credit rating, and (3)the production facility must have been placed in service collateral requirements or other credit enhancements such as letters before July 1,1998. Inaddition to meeting the qualifying conditions of credit or guarantees. We generally use standardized agreements for years through 2005, a taxpayer must have sufficient taxable that allow the netting of positive and negative transactions associated income to earn the production tax credits.

with a single counterparty.

To reduce U.S. dependence on imported oil, the Internal Revenue Interest Rate Risk Code provides production tax credits as an incentive for taxpayers to produce fuels from alternative sources. This incentive isnot We use interest rate swaps, treasury locks and other derivatives to deemed necessary if the price of oil increases and provides a natural hedge the risk associated with interest rate market volatility. In market for these fuels. As such, the tax credit in a given year is 2004 and 2000, we entered into a series of interest rate derivatives reduced if the Reference Price of oil within that year exceeds a to limit our sensitivity to market interest rate risk associated with threshold price. The Reference Price of a barrel of oil is an estimate the issuance of long-term debt. Such instruments were designated of the annual average wellhead price per barrel for domestic crude as cash flow hedges. We subsequently issued long-term debt oil. During 2005 the monthly average wellhead price per barrel of and terminated these hedges at a cost that isincluded in other oil for the year was approximately $6lower than the NYMEX price comprehensive loss. Amounts recorded in other comprehensive for light, sweet crude oil. The threshold price at which the credit loss will be reclassified to interest expense as the related interest begins to be reduced was set in 1980 and isadjusted annually for affects earnings through 2030. In2006, we estimate reclassifying inflation. For 2006, we estimate the threshold price at which the

$4million of losses to earnings. tax credit would begin to be reduced is$53 per barrel and would be completely phased out if the Reference Price reached $67 per Foreign Currency Risk barrel. As of February 28, 2006, the realized and unrealized NYMEX daily closing price of a barrel of oil was $65.08, equating to an DTE Energy Trading has foreign currency forward contracts to estimated Reference Price of $59, which iswithin the phase-out hedge fixed Canadian dollar commitments existing under power range. We cannot predict with any accuracy the future price of a purchase and sale contracts and gas transportation contracts. We barrel of oil. If,however, the Reference Price remained at this level entered into these contracts to mitigate any price volatility with throughout the remainder of 2006, we would experience a partial respect to fluctuations of the Canadian dollar relative to the U.S.

phase out of production tax credits.

dollar. Certain of these contracts were designated as cash flow hedges with changes in fair value recorded to other comprehensive Numerous events have increased domestic crude oil prices, including income. Amounts recorded to other comprehensive income are terrorism, storm-related supply disruptions and worldwide demand.

classified to operating revenues or fuel, purchased power and gas If the credit isreduced or eliminated in future years, our financial expense when the related hedged item affects earnings. statements may be negatively impacted. We continue to evaluate the current volatility inoil prices and alternatives available to mitigate Fair Value of Other Financial Instruments our exposure to oil prices. To manage our exposure to oil prices in The fair value of financial instruments isdetermined by using various 2006 and 2007, we entered into oil-related derivative contracts for market data and other valuation techniques. The table below a portion of our exposure. See Note 12.

shows the fair value relative to the carrying value for long-tenm debt Through December 31, 2005 we have generated and recorded securities. The carrying value of certain other financial instruments, approximately $557 million in synfuel tax credits.

such as notes payable, customer deposits and notes receivable approximate fair value and are not shown.

Environmental 2005 2004 FairValue CariyingValue FairValue CarryingValue Electric Utility Long-Term Debt S7.9 billion S7.7 billion $8.5 billion $ 8.0 billion Air- Detroit Edison issubject to EPA ozone transport and acid rain regulations that limit power plant emissions of sulfur dioxide and nitrogen oxides. InMarch 2005, EPA issued additional emission 68

reduction regulations relating to ozone, fine particulate, regional and affect the Company's financial position and cash flows. However, haze and mercury air pollution. The new rules will lead to additional we anticipate the cost deferral and rate recovery mechanism approved controls on fossil-fueled power plants to reduce nitrogen oxide, by the MPSC will prevent environmental costs from having amaterial sulfur dioxide and mercury emissions. To comply with these adverse impact on our results of operations.

requirements, Detroit Edison has spent approximately $644 million through 2005. We estimate Detroit Edison future capital expenditures Other at up to $218 million in 2006 and up to $2.2 billion of additional Our non-utility affiliates are subject to a number of environmental capital expenditures through 2018 to satisfy both the existing and laws and regulations dealing with the protection of the environment proposed new control requirements. Under the June 2000 Michigan from various pollutants. We are in the process of installing new restructuring legislation, beginning January 1,2004, annual return environmental equipment at our coke battery facilities in Michigan.

of and on this capital expenditure could be deferred in ratemaking, We expect the projects to be completed within two years at a cost until December 31, 2005, the expiration of the rate cap period.

of approximately $25 million. Our other non-utility affiliates are Water- Detroit Edison isrequired to examine alternatives for substantially in compliance with all environmental requirements.

reducing the environmental impacts of the cooling water intake structures at several of its facilities. Based on the results of the Guarantees studies to be conducted over the next several years, Detroit Edison Incertain circumstances we enter into contractual guarantees. We may be required to install additional control technologies to reduce may guarantee another entity's obligation inthe event it fails to the impacts of the intakes. It isestimated that we will incur up to perform. We may provide guarantees incertain indemnification

$50 million over the next four to six years in additional capital agreements. Finally, we may provide indirect guarantees for the expenditures for Detroit Edison. indebtedness of others. Below are the details of specific material guarantees we currently provide. Our other guarantees are not Contaminated Sites - Detroit Edison conducted remedial investigations individually material and total approximately $36 million at at contaminated sites, including two former MGP sites, the area December 31, 2005.

surrounding an ash landfill and several underground and above-ground storage tank locations. The findings of these investigations indicated that the estimated cost to remediate these sites is Sale of Interests in Synfuel Facilities approximately $13 million which was accrued in 2005 and is We have provided certain guarantees and indemnities inconjunction expected to be incurred over the next several years. with the sales of interests in our synfuel facilities. The guarantees cover general commercial, environmental, oil price and tax-related Gas Utility exposure and will survive until 90 days after expiration of all applicable Contaminated Sites - Prior to the construction of major interstate statute of limitations, or indefinitely, depending on the nature of natural gas pipelines, gas for heating and other uses was manufactured the guarantee. We estimate that our maximum liability under locally from processes involving coal, coke or oil. Gas Utility owns, these guarantees at December 31, 2005 is$1.8 billion.

or previously owned, 15 such former MGP sites. Investigations have revealed contamination related to the by-products of gas Parent Company Guarantee of Subsidiary Obligations manufacturing at each site. Inaddition to the MGP sites, we are We have issued guarantees for the benefit of various non-utility also inthe process of cleaning up other contaminated sites. subsidiary transactions. Inthe event that DTE Energy's credit rating Cleanup activities associated with these sites will be conducted isdowngraded below investment grade, certain of these guarantees over the next several years. would require us to post cash or letters of credit valued at approximately

$536 million at December 31, 2005. This estimated amount fluctuates In1993, a cost deferral and rate recovery mechanism was approved based upon commodity prices (primarily power and gas) and the by the MPSC for investigation and remediation costs incurred at provisions and maturities of the underlying agreements.

former MGP sites inexcess of this reserve. Gas Utility employed outside consultants to evaluate remediation alternatives for these sites, to assist in estimating its potential liabilities and to review Personal Property Taxes its archived insurance policies. As a result of these studies, Gas Detroit Edison, MichCon and other Michigan utilities have asserted Utility accrued an additional liability and a corresponding regulatory that Michigan's valuation tables result in the substantial overvaluation asset of $35 million during 1995. During 2005, we spent approximately of utility personal property. Valuation tables established by the

$4million investigating and remediating these former MGP sites. Michigan State Tax Commission (STC) are used to determine the InDecember 2005, we retained multiple environmental consultants taxable value of personal property based on the property's age. In to estimate the projected cost to remediate each MGP site. We November 1999, the STC approved new valuation tables that more accrued an additional $9million inremediation liabilities associated accurately recognize the value of autility's personal property. The new with two of our MGP sites, to increase the reserve balance to $35 tables became effective in 2000 and are currently used to calculate million at December 31, 2005. property tax expense. However, several local taxing jurisdictions have taken legal action attempting to prevent the STC from implementing Any significant change inassumptions, such as remediation techniques, the new valuation tables and have continued to prepare assessments nature and extent of contamination and regulatory requirements, based on the superseded tables. The legal actions regarding the could impact the estimate of remedial action costs for the sites appropriateness of the new tables were before the Michigan Tax 69

Tribunal (MTT) which, in April 2002, issued adecision essentially a result of FERC Order 637. The fair value amounts were being affirming the validity of the STC's new tables. InJune 2002, amortized to income over the life of the related agreements, petitioners in the case filed an appeal of the MTT's decision with representing a net liability of approximately $75 million as of the Michigan Court of Appeals. InJanuary 2004, the Michigan December 31, 2003. As a result of the contract modification and Court of Appeals upheld the validity of the new tables. With no termination, we recorded an adjustment to the net liability further appeal by the petitioners available, the MTT began to increasing 2004 earnings by $48 million, net of taxes.

schedule utility personal property valuation cases for Prehearing General Calls. After a period of abeyance the MTT issued a As of December 31, 2005, we were party to numerous long-term scheduling order in a significant number of Detroit Edison and purchase commitments relating to a variety of goods and services MichCon appeals that set litigation calendars for these cases required for our business. These agreements primarily consist of extending into mid-2006. After an extended period of settlement fuel supply commitments and energy trading contracts. We estimate discussions, a Memorandum of Understanding has been reached that these commitments will be approximately $6.7 billion through with six principals in the litigation and the Michigan Department of 2051. We also estimate that 2006 base level capital expenditures Treasury that isexpected to lead to settlement of all outstanding will be $1.2 billion. We have made certain commitments inconnection property tax disputes on a global basis. with expected capital expenditures.

On December 8, 2005 executed Stipulations for Consent Judgment, Bankruptcies Consent Judgments, and Schedules to Consent Judgment were filed with the MTT on behalf of Detroit Edison, MichCon and a significant We purchase and sell electricity, gas, coal, coke and other energy number of the largest jurisdictions, in terms of tax dollars, involved products from and to numerous companies operating in the steel, inthe litigation. The filing of these documents fulfilled the requirements automotive, energy, retail and other industries. Certain of our of the global settlement agreement and resolves a number of customers have filed for bankruptcy protection under Chapter 11 of claims by the litigants against each other including both property the U.S. Bankruptcy Code. We regularly review contingent matters and non-property issues. The global settlement agreement results relating to these customers and our purchase and sale contracts in an pre-tax economic benefit to DTE Energy of $43 million that and we record provisions for amounts considered at risk of probable includes the release of a litigation reserve. loss. We believe our previously accrued amounts are adequate for probable losses. The final resolution of these matters is not expected to have a material effect on our financial statements.

Other Commitments Detroit Edison has an Energy Purchase Agreement to purchase Other steam and electricity from the Greater Detroit Resource Recovery Authority (GDRRA). Under the Agreement, Detroit Edison will We are involved in certain legal, regulatory, administrative and purchase steam through 2008 and electricity through June 2024. environmental proceedings before various courts, arbitration panels In 1996, a special charge to income was recorded that included a and governmental agencies concerning claims arising inthe ordinary reserve for steam purchase commitments in excess of replacement course of business. These proceedings include certain contract costs from 1997 through 2008. The reserve for steam purchase disputes, environmental reviews and investigations, audits, inquiries commitments is being amortized to fuel, purchased power and gas from various regulators, and pending judicial matters. We cannot expense with non-cash accretion expense being recorded through predict the final disposition of such proceedings. We regularly 2008. We purchased $42 million of steam and electricity in 2005 review legal matters and record provisions for claims that are and 2004 and $39 million in2003. We estimate steam and electric considered probable of loss. The resolution of pending proceedings purchase commitments through 2024 will not exceed $427 million. is not expected to have a material effect on our operations or As discussed in Note 3,in January 2003, we sold the steam heating financial statements inthe period they are resolved.

business of Detroit Edison to Thermal Ventures II,LP. Due to terms of the sale, Detroit Edison remains contractually obligated to buy See Notes 4 and 5 for adiscussion of contingencies related to steam from GDRRA until 2008 and recorded an additional liability Regulatory Matters and Nuclear Operations.

of $20 million for future commitments. Also, we have guaranteed bank loans that Thermal Ventures II,LP may use for capital Note 14 - Retirement Benefits and improvements to the steam heating system.

Trusteed Assets In2004, we modified our future purchase commitments under a transportation agreement with an interstate pipeline company and Measurement Date terminated a related long-term gas exchange (storage) agreement. Inthe fourth quarter of 2004, we changed the date for actuarial Under the gas exchange agreement, we received gas from the measurement of our obligations for benefit programs from December customer during the summer injection period and redelivered the 31 to November 30. We believe the one-month change of the gas during the winter heating season. The agreements were at measurement date isa preferable change as it allows time for rates that were not reflective of current market conditions and had management to plan and execute its review of the completeness been fair valued under accounting principles generally accepted in and accuracy of its benefit programs results and to fully reflect the the U.S. In2002, the fair value of the transportation agreement impact on its financial results. The change did not have a material was frozen when it no longer met the definition of a derivative as effect on retained earnings as of January 1,2004, and income 70 I I

i

from continuing operations, net income and related per share substantially all employees and provide retirement benefits based on amounts for any interim period in 2004. Accordingly, all amounts the employees' years of benefit service, average final compensation reported inthe following tables for balances as of December 31, and age at retirement. Certain represented and nonrepresented 2005 and December 31, 2004 are based on measurement dates of employees are covered under cash balance benefits based on annual November 30, 2005 and November 30, 2004, respectively. Amounts employer contributions and interest credits. Our policy isto fund pension reported intables for the year ended December 31, 2005 are based costs by contributing the minimum amount required by the Employee on a measurement date of November 30, 2004. Amounts reported Retirement Income Security Act and additional amounts when we in tables for the year ended December 31, 2004 are based on a deem appropriate. We do not anticipate making a contribution to measurement date of December 31, 2003. Amounts reported intables our qualified pension plans in 2006.

for the year ended December 31, 2003 are based on a measurement date of December 31, 2002. We also maintain supplemental nonqualified, noncontributory, retirement benefit plans for selected management employees.

Qualified and Nonqualified Pension Plan Benefits These plans provide for benefits that supplement those provided by DTE Energy's other retirement plans.

We have defined benefit retirement plans for eligible represented and nonrepresented employees. The plans are noncontributory, cover Net pension cost includes the following components:

(inMillions) Qualified Pension Plans Nonqualified Pension Plans 2005 2004 2003 2005 2004 2003 Service Cost $64 $ 58 $ 48 $ 2 $ 2 $ 2 Interest Cost 169 168 164 3 3 4 Expected Return on Plan Assets (218) (216) (211) - - -

Amortization of Net loss 67 63 38 1 1 1 Prior service cost 8 8 8 - - -

Net Pension Cost $ 90 $ 81 $ 47 $ 6 $ 6 $ 7 The following table reconciles the obligations, assets and funded status of the plans as well as the amounts recognized as prepaid pension cost or pension liability in the consolidated statement of financial position at December 31:

Qualified Pension Plans Nonqualified Pension Plans (inMillions) 2005 2004 2005 2004 Accumulated Benefit Obligation-End of Period S 2741 $ 2,689 $ 61 $ 54 Projected Benefit Obligation-Beginning of Period $ Z899 $ 2,745 $ 56 $ 59 Service Cost 64 58 2 2 Interest Cost 169 168 3 3 Actuarial Loss (Gain) 49 76 10 (4)

Benefits Paid (168) (149) (4) (4)

Plan Amendments - I - -

Projected Benefit Obligation-End of Period $ 3,013 $ 2,899 S 67 $ 56 Plan Assets at Fair Value-Beginning of Period $ 2,565 $ 2,348 $ - $ -

Actual Return on Plan Assets 220 196 - -

Company Contributions - 170 4 4 Benefits Paid (168) (149) (4) (4)

Plan Assets at Fair Value-End of Period $ 2,617 $ 2,565 $ .- $ -

Funded Status of the Plans $ (396) $ (334) $ (67) $ (56)

Unrecognized Net loss 1,023 1,043 23 15 Prior service cost 27 34 2 1 Net Amount Recognized at Measurement Date 654 743 (42) (40)

December Adjustments - - 1 1 Net Amount Recognized-End of Period $ 654 $ 743 $ (41) $ (39)

Amount Recorded as Prepaid pension assets $ 186 $ 184 $ - $ -

Accrued pension liability (224) (212) (60) (53)

Regulatory asset 532 594 12 11 Accumulated other comprehensive loss 129 139 5 2 Intangible asset 31 38 2 1 S 654 $ 743 $ (41) $ (39) 71

Assumptions used in determining the projected benefit obligation market value of the underlying investments. Investment risk is and net pension costs are listed below: measured and monitored on an ongoing basis through annual liability measurements, periodic asset/liability studies, and 2005 2004 2003 quarterly investment portfolio reviews.

Projected Benefit Obligation Discount rate 5.90% 6.00% 6.25% Our plans' weighted-average asset allocations by asset category at Annual increase infuture December 31 were as follows:

compensation levels 4.0 % 4.0 % 4.0% 2005 2004 Net Pension Costs Equity Securities 68% 69%

Discount rate 6.00 % 6.25 % 6.75% Debt Securities 27 26 Annual increase infuture Other 5 5 compensation levels 4.0 % 4.0 % 4.0%

100% 100%

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

Our plans' weighted-average asset target allocations by asset category at December 31, 2005 were as follows:

At December 31, 2005, the benefits related to our qualified and nonqualified plans expected to be paid ineach of the next five years Equity Securities 65%

and inthe aggregate for the five fiscal years thereafter are as follows:

Debt Securities 28 (inMillions) Other 7 100%

2006 $ 174 2007 177 2008 183 InDecember 2002, we recognized an additional minimum pension 2009 188 liability as required under SFAS No. 87, Employers'Accounting for 2010 193 Pensions. An additional pension liability may be required when the 2011 -2015 1,046 accumulated benefit obligation of the plan exceeds the fair value of

$ 1,961 plan assets. Under SFAS No. 87, we recorded an additional minimum Total pension liability, an intangible asset and other comprehensive loss.

In2003, we reclassified $572 million of other comprehensive loss We employ a consistent formal process in determining the long- related to Detroit Edison's minimum pension liability to a regulatory term rate of return for various asset classes. We evaluate input asset after the MPSC Staff provided an opinion that the MPSC's from our consultants, including their review of historic financial traditional rate setting process allowed for the recovery of pension market risks and returns and long-term historic relationships costs as measured by SEAS No. 87. The additional minimum pension between the asset classes of equities, fixed income and other liability, regulatory asset, intangible asset and other comprehensive assets, consistent with the widely accepted capital market princi- loss are adjusted in December of each year based on the plans' ple that asset classes with higher volatility generate a greater funded status.

return over the long-term. Current market factors such as inflation, interest rates, asset class risks and asset class returns are evaluat- We also sponsor defined contribution retirement savings plans.

ed and considered before long-term capital market assumptions Participation in one of these plans isavailable to substantially all are determined. The long-term portfolio return is also established represented and nonrepresented employees. We match employee employing a consistent formal process, with due consideration of contributions up to certain predefined limits based upon eligible diversification, active investment management and rebalancing. compensation, the employee's contribution rate and, in some Peer data isreviewed to check for reasonableness. cases, years of credited service. The cost of these plans was $29 million in 2005, $28 million in 2004 and $26 million in2003.

We employ a total return investment approach whereby a mix of equities, fixed income and other investments are used to maximize Other Postretirement Benefits the long-term return of plan assets consistent with prudent levels of risk. The intent of this strategy isto minimize plan expenses over We provide certain postretirement health care and life insurance the long-term. Risk tolerance isestablished through consideration benefits for employees who are eligible for these benefits. Our of future plan cash flows, plan funded status, and corporate financial policy isto fund certain trusts to meet our postretiremnent benefit considerations. The investment portfolio contains a diversified obligations. Separate qualified Voluntary Employees Beneficiary blend of equity, fixed income and other investments. Furthermore, Association (VEBA) trusts exist for represented and nonrepresented equity investments are diversified across U.S. and non-U.S. stocks, employees. At the discretion of management, we may make up to growth and value investment styles, and large and small market a $120 million contribution to our VEBA trusts in 2006.

capitalizations. Other assets such as private equity and absolute return funds are used judiciously to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure inan efficient and timely manner, however, derivatives may not be used to leverage the portfolio beyond the 72

Net postretirement cost includes the following components: inhealth care cost trend rates would have increased the total service cost and interest cost components of benefit costs by $32 million (inMillions) 2005 2004 2003 and increased the accumulated benefit obligation by $244 million Service Cost $ 55 $ 41 $ 37 at December 31, 2005. A one-percentage-point decrease inthe Interest Cost 105 92 87 health care cost trend rates would have decreased the total service Expected Return on Plan Assets (70) (56) (47) and interest cost components of benefit costs by $20 million and Amortization of would have decreased the accumulated benefit obligation by $203 Net loss 60 43 31 million at December 31, 2005.

Prior service cost (2) (3) (3)

Net transition obligation 7 8 13 At December 31, 2005, the benefits expected to be paid, including Net Postretirement Cost $ 155 $ 125 $ 118 prescription drug benefits, ineach of the next five years and inthe aggregate for the five fiscal years thereafter are as follows:

The following table reconciles the obligations, assets and funded (inMillions) status of the plans including amounts recorded as accrued 2006 $ 111 postretirement cost in the consolidated statement of financial 2007 116 position at December 31: 2008 120 (inMillions) 2005 2004 2009 125 Accumulated Postretirement 2010 128 Benefit Obligation-Beginning of Period $ 1,793 $ 1,582 2011 -2015 670 Service Cost 55 41 Total $ 1,270 Interest Cost 105 92 Actuarial Loss 136 146 The process used indetermining the long-term rate of return for assets Plan Amendments (10) 7 and the investment approach for our other postretirement benefits plans Benefits Paid (88) (75) issimilar to those previously described for our qualified pension plans.

Accumulated Postretirement Benefit Obligation-End of Period S 1,991 $ 1,793 Our plans' weighted-average asset allocations by asset category at Plan Assets at Fair Value-Beginning of Period $ 679 $ 586 December 31 were as follows:

Actual Return on Plan Assets 61 53 2005 2004 Company Contributions 40 40 Equity Securities 68 % 68%

Benefits Paid (67) - Debt Securities 28 28 Plan Assets at Fair Value-End of Period $ 713 $ 679 Other 4 4 Funded Status of the Plans $ (1278) $ (1,114) 100% 100%

Unrecognized Net loss 896 811 Our plans' weighted-average asset target allocations by asset Prior service cost (12) (8) category at December 31, 2005 were as follows:

Nettransition obligation 46 58 Accrued Postretirement Liability Equity Securities 65%

at Measurement Date (348) (253) Debt Securities 28 December Adjustments (58) (20) Other 7 Accrued Postretirement 100%

Liability-End of Period S (406) $ (273)

InDecember 2003, the Medicare Act was signed into law which Assumptions used in determining the projected benefit obligation provides for anon-taxable federal subsidy to sponsors of retiree health and net benefit costs are listed below: care benefit plans that provide a benefit that isat least "actuarially (inMillions) 2005 2004 2003 equivalent" to the benefit established by law. As discussed in Note 2, Projected Benefit Obligation we adopted FSP No. 106-2 in2004, which provides guidance on the Discount rate 5.90 % 6.00% 6.25% accounting for the Medicare Act. As a result of the adoption, our Net Benefit Costs accumulated postretirement benefit obligation for the subsidy related Discount rate 6.00 % 6.25 % 6.75% to benefits attributed to past service was reduced by approximately Expected long-term rate of $95 million at January 1,2004 and was accounted for as an actuarial return on Plan assets 9.0 % 9.0 % 9.0 % gain. The effects of the subsidy reduced net periodic postretirement benefit costs by $20 million in2005 and $16 million in2004.

Benefit costs were calculated assuming health care cost trend At December 31, 2005, the gross amount of federal subsidies rates beginning at 9%for 2006 and decreasing to 5%in 2011 and expected to be received in each of the next five years and in the thereafter for persons under age 65 and decreasing from 8%to aggregate for the five fiscal years thereafter was as follows:

5%for persons age 65 and over. A one-percentage-point increase 73

(inMillions) The number, weighted average exercise price and weighted average 2006 $ 6 remaining contractual life of options outstanding were as follows:

2007 4 2008 5 Weighted Weighted Average Range of Number of Average Remaining 2009 6 Exercise Prices Options Exercise Price Contractual Life 2010 5 $ 27.62 - $ 38.04 423,473 $ 31.34 3.97 years 2011 - 2015 35 $ 38.60 -$ 42.44 3,728,512 $ 40.64 6.76 years Total $ 61 $ 42.60 - $ 44.54 482,110 $ 42.65 5.35 years

$44.56 - $ 48.00 1,602,248 $45.09 7.47 years Grantor Trust 6,236,343 $41.31 6.64 years MichCon maintains a Grantor Trust that invests in life insurance We account for option awards under APB Opinion 25. Accordingly, contracts and income securities. Employees and retirees have no no compensation expense has been recorded for options granted.

right, title or interest in the assets of the Grantor Trust, and As required by SFAS No. 123, we have determined the fair value MichCon can revoke the trust subject to providing the MPSC with for these options at the date of grant using a Black-Scholes based prior notification. We account for our investment at fair value with option pricing model and the following assumptions:

unrealized gains and losses recorded to earnings.

2005 2004 2003 Risk-free interest rate 3.93% 3.55% 2.93%

Note 15 - Stock-based Compensation Dividend yield 4.60 % 5.23% 4.97%

The DTE Energy Stock Incentive Plan permits the grant of incentive Expected volatility 19.56 % 20.00% 20.89%

stock options, non-qualifying stock options, stock awards, performance shares and performance units. A maximum of 18 million shares of Expected life 6 years 6 years 6 years common stock may be issued under the plan. Participants in the plan include our employees and members of our Board of Directors. Fair value per option S 5.89 $ 4.46 $ 4.78 As of December 31, 2005, no performance units have been granted under the plan.

Stock Awards Options Stock awards granted under the plan are restricted for varying periods, which are generally for three years. Participants have all Options are exercisable according to the terms of the individual rights of a shareholder with respect to a stock award, including the stock option award agreements and expire 10 years after the date right to receive dividends and vote the shares. Prior to vesting in of the grant. The option exercise price equals the fair value of the stock awards, the participant: (i)may not sell, transfer, pledge, stock on the date that the option was granted. Stock option activity exchange or otherwise dispose of shares; (ii) shall not retain was as follows: custody of the share certificates; and (iii) will deliver to us a stock Weighted Number Average power with respect to each stock award.

of Exercise Options Price The stock awards are recorded at cost that approximates fair value Outstanding at December 31, 2002 on the date of grant. We account for stock awards as unearned (2,285,323 exercisable) 5,480,595 $ 39.87 compensation, which isrecorded as a reduction to common stock.

Granted 1,654,879 $ 40.56 The cost isamortized to compensation expense over the vesting Exercised (329,528) $ 35.88 period. Stock award activity for the years ended December 31 was:

Canceled (152,824) $ 42.67 2005 2004 2003 Outstanding at December 31, 2003 (3,506,038 exercisable) 6,653,122 $ 40.18 Restricted common shares awarded 288,360 209,650 102,060 Granted 1,300,900 $ 39.41 Weighted average market Exercised (891,353) $ 34.94 price of shares awarded S 44.95 $ 39.95 $ 41.39 Canceled (356,000) $ 43.06 Compensation cost charged Outstanding at December 31,2004 against income (in thousands) S 7,747 $ 5,616 $ 6,366 (3,939,939 exercisable) 6,706,669 $ 40.57 Granted 955,899 $ 44.79 Exercised (1,291,645) $ 39.92 Performance Share Awards Canceled (134,580) S 42.33 Performance shares awarded under the plan are for a specified Outstanding at December 31,2005 number of shares of common stock that entitles the holder to (4,029,444 exercisable at aweighted receive a cash payment, shares of common stock or a combination average exercise price of $40.88) 6,236,343 $ 41.31 thereof. The final value of the award isdetermined by the achievement of certain performance objectives. The awards vest 74

at the end of aspecified period, usually three years. We account tax benefit of production tax credits and net operating losses. The for performance share awards by accruing compensation expense subsidiaries record income tax payable to or receivable from DTE over the vesting period based on: (i)the number of shares expected Energy resulting from the inclusion of its taxable income or loss in to be paid which isbased on the probable achievement of performance DTE Energy's consolidated tax return.

objectives; and (ii)the fair value of the shares. For 2005, 2004 and 2003, we recorded compensation expense totaling $5million, $6 Inter-segment billing for goods and services exchanged between million and $6million, respectively. segments isbased upon tariffed or market-based prices of the provider and primarily consists of power sales, gas sales and coal During the vesting period, the recipient of aperformance share transportation services inthe following segments:

award has no shareholder rights. However, recipients will be paid an amount equal to the dividend equivalent on such shares. (inMillions) 2005 2004 2003 Performance share awards are nontransferable and are subject to Electric Utility S 207 $ 218 S 69 risk of forfeiture. As of December 31, 2005, there were 803,071 Unconventional Gas Production 154 121 114 performance share awards outstanding. Fuel Transportation and Marketing 268 253 66 S 629 $ 592 S 249 Note 16 - Segment And Related Information We operate our businesses through three strategic business units, Electric Utility, Gas Utility and Non-Utility Operations. The balance of our business consists of Corporate & Other. Based on this structure, we set strategic goals, allocate resources and evaluate performance. This results in the following reportable segments:

Electric Utility

Consists of Detroit Edison, the company's electric utility whose operations include the power generation and electric distribution facilities that service approximately 2.2 million residential, commercial and industrial customers throughout southeastern Michigan.

Gas Utility

Consists of the gas distribution services provided by MichCon, a gas utility that purchases, stores and distributes natural gas throughout Michigan to approximately 1.3 million residential, commercial and industrial customers and Citizens Gas Fuel Company, a gas utility that distributes natural gas inAdrian, Michigan.

Non-utility Operations

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

Unconventional Gas Production, primarily consisting of natural gas exploration, development and production; and

Fuel Transportation and Marketing, primarily consisting of energy marketing and trading operations, coal transportation and marketing, and gas pipelines, processing and storage.

Corporate & Other, primarily consisting of corporate support functions and certain energy related investments.

The income tax provisions or benefits of DTE Energy's subsidiaries are determined on an individual company basis and recognize the 75

Financial data of the business segments follows:

(inMillions) Depr eciation, Operating Depletion & Interest Interest Income Net Total Capital 2005 Revenue Amortization Income Expense Taxes Income Assets Goodwill Expenditures Electric Utility $ 4,462 $ 640 $ (3) $ 267 $ 149 $ 277 S 13,112 $ 1,207 $ 722 Gas Utility 2,138 95 (10) 58 (2) 37 3,101 772 128 Non-utility Operations:

Power and Industrial Projects 1,356 107 (41) 21 89 308 2,117 41 31 Unconventional Gas Production 74 20 - 8 1 4 434 8 144 Fuel Transportation and Marketing 1,684 7 (6) 21 (1) 2 2,207 29 36 3,114 134 (47) 50 89 314 4,758 78 211 Corporate & Other 10 - (40) 187 (34) (52) 2,358 - 4 Reconciliation and Eliminations (702) - 43 (43) - - - - -

Total from Continuing Operations S 9,022 $ 869 $ (57) $ 519 $ 202 576 23,329 2,057 1,065 Discontinued Operations (Note 3) (36) 6 - -

Cumulative Effect of Accounting Change (Note 2) (3) - - -

Total $ 537 $23,335 $ 2,057 $ 1,065 (inMillions) Depreciation, Operating Depletion & Interest Interest Income Net Total Capital 2004 Revenue Amortization Income Expense Taxes Income Assets Goodwill Expenditures Electric Utility $ 3,568 $ 523 $ - $ 280 $ 64 $ 150 $ 12,708 $ 1,202 $ 702 Gas Utility 1,682 103 (9) 58 (9) 20 2,816 772 113 Non-utility Operations:

Power and Industrial Projects 1,100 89 (43) 35 42 179 1,841 41 24 Unconventional Gas Production 71 18 - 10 3 6 301 8 38 Fuel Transportation and Marketing 1,254 6 (4) 8 64 118 1,280 28 24 2,425 113 (47) 53 109 303 3,422 77 86 Corporate & Other 17 3 (48) 174 10 (12) 2,284 - 2 Reconciliation and Eliminations (621) - 49 (49)

Total from Continuing Operations $ 7,071 $ 742 $ (55) $ 516 $ 174 461 21,230 2,051 903 Discontinued Operations (Note 3) 130) 67 16 1 Total $ 431 $21,297 S 2,067 $ 904 (inMillions) Depreciation, Operating Depletion & Interest Interest Income Net Total Capital 2003 Revenue Amortization Income Expense Taxes Income Assets Goodwill Expenditures Electric Utility $ 3,695 $ 473 $ (7) S 284 $ 145 $ 252 $ 12,502 S 1,202 $ 580 Gas Utility 1,498 101 (10) 58 - 29 2,719 776 99 Non-utility Operations:

Power and Industrial Projects 938 90 (16) 21 (271) 197 1,690 41 26 Unconventional Gas Production 70 17 - 7 5 12 282 8 28 Fuel Transportation and Marketing 1,061 4 (3) 6 41 69 1,089 28 13 2,069 ill (19) 34 (225) 278 3,061 77 67 Corporate & Other 16 (33) 201 (36) (65) 2,400 4 Reconciliation and Eliminations (273) 32 (32)

Total from Continuing Operations S 7,005 S 685 $ (37) $ 545 S 1116) 494 20,682 2,055 750 Discontinued Operations (Note 3) $ {37) 54 71 12 1 Cumulative Effect of Accounting Change (Note 2) (271 -

Total $ 521 $ 20,753 S 2,067 $ -

751 76

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. Dtech was reported as a discontinued operation beginning in the third quarter 2005, resulting in the adjustment of prior quarterly results. See Note 3.

(inMillions, except per share amounts) First Second Third Fourth 2005 Quarter Quarter Quarter Quarter Year Operating Revenues S 2309 $ 1,941 $ 2,060 $ 2,712 $ 9,022 Operating Income $ 224 $ 90 S 51 S 581 $ 946 Net Income iLoss)

From continuing operations S 126 $ 33 $ 29 $ 388 S 576 Discontnued operations (4) (4) (25) (3) (36)

Cumulative effect of accounting change - - (3) (3)

Total $ 122 $ 29 $ 4 S 382 $ 537 Basic Earnings (Loss) per Share From continuing operations S .72 S .19 $ .17 $ 2.19 $ 329 Discontinued operations (.02) (.02) (.15) (.01) (20)

Cumulative effect of accounting change - - - (.02) (.02)

Total S .70 S .17 S .02 S 2.16 $ 3.07 Diluted Earnings (Loss) per Share From continuing operations S .72 S .19 $ .17 S 2.18 $ 327 Discontinued operabons (.02) (.02) (.15) (.02) (.20)

Cumulative effect of accounting change - - - (.02) (.02)

Total $ .70 S .17 $ .02 S 2.14 $ 3.05 2004 Operating Revenues $ 2,082 $ 1,490 $ 1,586 $ 1,913 $ 7,071 Operating Income $ 372 $ 106 $ 177 $ 215 $ 870 Net Income (Loss)

From continuing operations $ 200 $ 43 $ 97 $ 121 $ 461 Discontinued operations (10) (8) (4) (8) (30)

Total $ 190 $ 35 $ 93 $ 113 $ 431 Basic Earnings (Loss) per Share From continuing operations $ 1.18 $ .25 $ .56 $ .69 $ 2.67 Discontinued operations (.06) (.05) (.02) (.04) (.17)

Total $ 1.12 $ .20 $ .54 $ .65 $ 2.50 Diluted Earnings (Loss) per Share From continuing operations $ 1.17 $ .25 $ .56 $ .69 $ 2.66 Discontinued operations (.06) (.05) (.02) (.04) (.17)

Total $ 1.11 $ .20 $ .54 $ .65 $ 2.49 77

D,?,-t,-,=ITE Energy, Company--y;:;, -,;, ,

1 La X oh=:R~ie (Dollars inMillions, Except Common Share Data) 2005 2004 2003 2002 Operating Revenues Utility $ 6,600 $ 5,250 $ 5,193 $ 5,423 Non-utility (1) 2,422 1,821 1,812 1,271 Total S 9,022 $ 7,071 $ 7,005 $ 6,694 Net Income Utility $ 314 $ 170 $ 281 $ 418 Non-utility (1) 262 291 213 181 576 461 494 599 Discontinued Operations (36) (30) 54 33 Cumulative Effect of Accounting Changes (3) - (27) -

S 537 $ 431 S 521 $ 632 Diluted Earnings per Share Utility S 1.78 $ 0.98 $ 1.67 $ 2.53 Non-utility (1) 1.49 1.68 1.26 1.10 3.27 2.66 2.93 3.63 Discontinued Operations (0.20) (0.17) 0.32 0.20 Cumulative Effect of Accounting Changes (0.02) - (0.16)

S 3.05 $ 2.49 $ 3.09 $ 3.83 Electric Utility Deliveries (Millions of kWh) 54,744 52,416 53,194 54,105 Electric Utility Customers at Year End (Thousands) Z159 2,146 2,132 2,136 Gas Utility Deliveries (Bcf) (2) 757 854 909 837 Gas Utility Customers at Year End (Thousands) (2) 1,270 1,258 1,249 1,267 Financial Position at Year End Net property (3) $ 10,830 $ 10,491- $ 10,324 S 10,542 Total assets (3) $ 23,335 $ 21,297 $ 20,753 $ 19,985 Long-term debt, including capital leases $ 7,080 $ 7,606 $ 7,669 S 7,803 Total shareholders' equity S 5,769 $ 5,548 $ 5,287 S 4,565 Common Share Data Dividends declared per share $ 2.06 $ 2.06 $ 2.06 $ 2.06 Average shares outstanding-diluted (millions) 176 173 168 165 Book value per share $ 32.44 $ 31.85 $ 31.36 S 27.26 Market price: High $ 48.31 $ 45.49 $ 49.50 $ 47.70 Low $ 41.39 $ 37.88 $ 34.00 S 33.05 Year end $ 43.19 $ 43.13 $ 39.40 $ 46.40 Miscellaneous Financial Data Cash flow from operations $ 1,001 $ 995 $ 950 $ 996 Capital expenditures $ 1,065 $ 904 $ 751 $ 984 Employees atyear end 11,410 11,207 11,099 11,095 (11Includes Corporate & Other and/or eliminations.

(21Gas Utility data shown prior to May 2001is presented for informational purposes only. The Gas Utility business was acquired on May 31, 2001.

(31In conjunction with adopting SFAS No. 143, we reclassified previously accrued asset removal costs related to our regulated operations, which had been previously netted against accumulated depreciation, to an asset removal cost liability forthe years 1999 through 200Z Amounts for years priorto 1999 are not available 78

F. DTE Energy Company K -

I SttisticaI Review

.,4,,.

2001 2000 1999 1998 1997 1996 1995 f $ 4,659 S 4,129 $ 4,047 $ 3,902 $ 3,657 $ 3,642 $ 3,634 1,112 509 452 272 107 3 2

$ 5,771 $ 4,638 $ 4,499 $ 4,174 $ 3,764 $ 3,645 $ 3,636

$ 198 $ 427 $ 434 $ 412 $ 405 $ 312 $ 406 119 41 49 31 12 3) -

317 468 483 443 417 309 406 r 12 3

$ 332 $ 468 $ 483 $ 443 $ 417 $ 309 $ 406

$ 1.29 $ 2.99 $ 3.00 $ 2.83 $ 2.79 $ 2.15 $ 2.80 0.77 0.28 0.33 0.22 0.09 (0.02) -

2.06 3.27 3.33 3.05 2.88 2.13 2.80 0.08 - - - - - -

0.02 - - - - - -

$ 2.16 $ 3.27 $ 3.33 $ 3.05 $ 2.88 $ 2.13 $ 2.80 51,516 52,611 55,871 55,286 50,983 48,815 49,298 2,125 2,110 2,089 2,068 2,051 2,025 2,002 917 945 866 850 941 895 730 1,235 1,235 1,220 1,206 1,193 1,183 1,173

$ 10,255 $ 8,081 $ 7,853 $ - $ - $ - $ -

$ 19,587 $ 13,350 $ 13,021 $ - $ - $ - $ -

$ 7,928 $ 4,039 $ 4,091 $ 4,323 $ 3,914 $ 3,894 $ 3,884

$ 4,589 $ 4,009 $ 3,909 $ 3,698 $ 3,706 $ 3,588 $ 3,763

$ 2.06 $ 2.06 $ 2.06 $ 2.06 $ 2.06 $ 2.06 $ 2.06 154 143 145 145 145 145 145 S 28.48 $ 28.14 $ 26.75 $ 25.49 $ 24.51 $ 23.69 $ 23.62

$ 47.13 $ 41.25 $ 44.69 $ 49.25 $ 34.75 $ 37.25 $ 34.88

$ 33.13 $ 28.44 $ 31.06 $ 33.50 $ 26.13 $ 27.63 $ 25.75

$ 41.94 $ 38.94 $ 31.63 $ 43.06 $ 34.69 $ 32.38 $ 34.50

$ 811 $ 1,015 $ 1,084 $ 834 $ 905 $ 1,079 $ 913 S 1,096 $ 749 $ 739 $ 589 $ 484 $ 531 $ 454 11,030 9,144 8,886 8,781 8,732 8,526 8340 79

Words Our Industry UsesI

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Cogeneratlon.,

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industrial,1/4znrrieci l heain A;r o' thY--I-~~

coolin p~,~se . ~. -~~St ,j .- 5 Purchaseduhrts poweE t expenses.~

ul ulrltdadC Coke and-- I Cok,5 Batteryr--~~,7,,---~ .

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,1 vary each year, as determIned b~h , Interna

- -. ~ '-.'. ~ - ,~ , ~~~-~~t' i.. ~- ,'--,,~-, 1, .4.'?' 4I ~ I 1 1.. ~1,~ , I el enericitytnd gas.t-; 44-! P`-~~jii tinFudigLL.

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comrissi-nre-ulates -. --- -' Synthetic-Fuel- . . 4- 4 (Synfuel)

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Pet-~ coke-- is a solid1byproduct geneation ad oke pbdu'cti&Synfu

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~ ~ ~ ~. of the oil~ cedts

.'~j 444-6 dand ,~,---,-

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~

80

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-Board and officer bios

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Survey results will be available online at www.dteenergy.com in July 2006.

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I-I I

NO POSTAGE NECESSARY IF MAILED IN THE BUSINESS REPLY MAIL UNITED STATES I FIRST-CLASS MAIL PERMIT NO. 61 DETROIT Ml POSTAGE WILL BE PAID BYTHE ADDRESSEE ATTN WRITING RESOURCES 1571 WCB DTE ENERGY 2000 2ND AVE.

DETROIT MI 48226-9886 liii IIIIIIIhIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIIII

the nfo n AboutDTE Ener 81! :as_.

DTE Energy common stock is listed on the New York Stock Independent Registered Public Accounting Firm Exchange and the Chicago Stock Exchange (symbol DTE). Deloitte & Touche LLP The following table indicates the reported high and low sale 600 Renaissance Center, Suite 900 prices on the New York Stock Exchange Composite Tape for Detroit, Ml 48243-1704 OTE Energy common stock, and dividends paid per share for each quarterly period during the past two years: Form 10-K We will provide, without charge to shareholders, copies Dividends Paid of our Form 10-K filed with the Securities and Exchange Calendar Quarter High Low Per Share Commission. Written requests should be directed to:

2005 First $46.99 $ 42.40 $ 0.515 Sandra Kay Ennis Second 48.31 44.40 0.515 Corporate Secretary Third 48.22 44.11 0.515 DTE Energy, 2000 Second Ave.

Fourth 46.65 41.39 0.515 Detroit, Ml 48226-1279 2004 First $42.29 $ 37.92 $ 0.515 dteenergy.com/investors Second 41.58 37.88 0.515 Third 42.21 39.31 0.515 Officer Certifications Fourth 45.49 41.44 0.515 In 2005, our chief executive officer (CEO) submitted to the New York Stock Exchange (NYSE) the annual CEO As of Dec. 31, 2005,177,814,429 shares of the company's certification regarding DTE Energys compliance with the common stock were outstanding. These shares were held by NYSE's corporate governance listing standards, stating that atotal of 94,981 shareholders of record. he was not aware of any violation to the NYSE corporate governance listing standards. Our CEO made his annual Distribution of ownership of DTE Energy common stock as of certification to the NYSE as of May 27, 2005. In addition, we Dec. 31, 2005: have filed as exhibits to the Annual Report on Form 10-K with the Securities and Exchange Commission, the certifications Type of Owner Owners Shares required under Section 302 of the Sarbanes-Oxley Act Joint Accounts 35,079 14,519,532 of 2002 regarding the quality of the company's public Individual 39,052 11,931,684 disclosures in the fiscal year-end 2005 reports.

Individual Custodian 17,729 7,323,554 Trust Accounts 2,223 1,486,393 Transfer Agent and Registrar of Stock Banks & Nominees 45 142,011,279 The Bank of New York Corporations & Insurance Co's. 135 171,348 Receive and Deliver Department, P.O. Box 11002 Institutions & Foundations 42 42,049 Church Street Station, New York, NY 10286 Brokers/Security Dealers 48 30,799 Telephone: 866.388.8558 stockbny.com Churches & Religious Orgs. 99 27,978 All Others 529 269,813 Shareholder Inquiries and Other Information Total 94,981 177,814,429 The Bank of New York, Shareholder Relations Department P.O. Box 11258, Church Street Station, New York, NY 10286 State and Country Owners Shares e-mail inquiries to: shareowners~bankofny.com Michigan 19,025 19,629,161 Florida 5,591 2,449,880 DTE Energy shareholders of record can authorize the agent California 4,646 1,605,999 to deposit their dividend payments in a financial institution NewYork 3,680 143,218,934 account of their choice on the payment date. In addition, Illinois 3,565 1,315,153 shareholders of record can purchase DTE Energy common Ohio 2,958 987,468 stock with their dividends through the Dividend Reinvestment 44 Other States 55,123 8,493,200 & Stock Purchase Plan. For more information about direct Foreign Countries 393 114,634 deposit and dividend reinvestment, visit the agent's Web site, Total 94,981 177,814,429 stockbny.com or call 866.388.8558.

Annual Meeting of Shareholders Shareholders of record can request information about The 2006 Annual Meeting of DTE Energy Shareholders will receiving their future annual report and proxy materials over be held Thursday, April 27, 2006, at 10 a.m. Detroit time in the Internet by marking the appropriate box on their proxy the DTE Energy Building, 660 Plaza Drive, Detroit, Ml. card as instructed. By electing electronic delivery, you are stating that you currently have or expect to have access to Corporate Address the Internet.

DTE Energy, 2000 Second Ave. ©2006 DTE Energy is the owner Printed by Detroit, Ml 48226-1279 D TE DTE Energy Company, of the "Head/Corona" all rights reserved. logo. DTE Energy or Sandy Alexander Inc Clifton, NJ Telephone: 313.235.4000 dteenergy.com its affiliates are the NYSE.owners of various other registered and X90G 4 unregistered trademarks.

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,I:4 vi A

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