10-K

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

FORM 10-K

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

For the fiscal year ended December 31, 2002

Commission file number 1-7310

Michigan Consolidated Gas Company, a Michigan corporation, meets the conditions set forth in General Instruction I (1) (a) and (b) of Form 10-K and is, therefore, filing this form with the reduced disclosure format.

MICHIGAN CONSOLIDATED GAS COMPANY
(Exact name of registrant as specified in its charter)

Michigan	38-0478040
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
2000 2nd Avenue, Detroit, Michigan	48226-1279
(Address of principal executive offices)	(Zip Code)

313-965-2430
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
6.85% Senior Secured Insured Quarterly Notes	New York Stock Exchange
6 1/8% Senior Notes	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None
 

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

Yes   X        No            

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendments to this Form 10-K. [ X ]

All of the registrant’s 10,300,000 outstanding shares of common stock, par value $1 per share, are indirectly owned by DTE Energy Company.

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS

DEFINITIONS
FORWARD-LOOKING STATEMENTS
PART I
	Items 1 & 2. Business & Properties
	Item 3. Legal Proceedings
	Item 4. Submission of Matters to a Vote of Security Holders
PART II
	Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters
	Item 6. Selected Financial Data
	Item 7. Management’s Narrative Analysis of Results of Operations
	Item 7A. Quantitative and Qualitative Disclosures About Market Risk
	Item 8. Financial Statements and Supplementary Data
	Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
PART III
	Item 10. Directors and Executive Officers of the Registrant
	Item 11. Executive Compensation
	Item 12. Security Ownership of Certain Beneficial Owners and Management
	Item 13. Certain Relationships and Related Transactions
PART IV
	Item 14. Controls and Procedures
	Item 15. Exhibits, Financial Statement Schedule, and Reports on Form 8-K
SIGNATURES
CERTIFICATIONS
Computation of Ratio of Earnings to Fixed Charges
Consent of Deloitte & Touche LLP
Chief Executive Officer Certification
Chief Financial Officer Certification

MICHIGAN CONSOLIDATED GAS COMPANY

ANNUAL REPORT ON FORM 10-K
YEAR ENDED DECEMBER 31, 2002

TABLE OF CONTENTS

		PAGE
DEFINITIONS			1
FORWARD-LOOKING STATEMENTS			3
PART I
Items 1 & 2.	Business & Properties		4
Item 3.	Legal Proceedings		10
Item 4.	Submission of Matters to a Vote of Security Holders		11
PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters		11
Item 6.	Selected Financial Data		11
Item 7.	Management’s Narrative Analysis of Results of Operations		12
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		16
Item 8.	Financial Statements and Supplementary Data		18
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		44
PART III
Item 10.	Directors and Executive Officers of the Registrant		44
Item 11.	Executive Compensation		44
Item 12.	Security Ownership of Certain Beneficial Owners and Management		44
Item 13.	Certain Relationships and Related Transactions		44
PART IV
Item 14.	Controls and Procedures		45
Item 15.	Exhibits, Financial Statement Schedule, and Reports on Form 8-K		45
SIGNATURES			48
CERTIFICATIONS			49

DEFINITIONS

Customer Choice	The choice program is a statewide initiative giving customers in Michigan the option to choose alternative suppliers for gas.
DTE Energy	DTE Energy Company and subsidiary companies.
End User Transportation	A gas delivery service historically provided to large-volume commercial and industrial customers who purchase natural gas directly from producers or brokerage companies. Under MichCon’s Customer Choice Program that began in 1999, this service is also provided to residential customers and small-volume commercial and industrial customers.
Enterprises	DTE Enterprises Inc. (formerly MCN Energy).
FERC	Federal Energy Regulatory Commission; a federal agency that determines the rates and regulations of interstate pipelines.
Gas Sales Program	A three-year program that ended in December 2001 under which MichCon’s gas sales rate included a gas commodity component that was fixed at $2.95 per Mcf.
Gas Storage	For MichCon, the process of injecting, storing and withdrawing natural gas from a depleted underground natural gas field.
GCR	A gas cost recovery mechanism authorized by the MPSC that was reinstated by MichCon in January 2002 permitting MichCon to pass on the cost of natural gas to its customers.
Intermediate Transportation	A gas delivery service provided to producers, brokers and other gas companies that own the natural gas, but are not the ultimate consumers.
MCN Energy	MCN Energy Group Inc. and subsidiary companies.
MichCon	Michigan Consolidated Gas Company; an indirect, wholly-owned natural gas distribution and intrastate transmission subsidiary of Enterprises.

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MPSC	Michigan Public Service Commission.
Normal Weather	The average daily temperature within MichCon’s service area during a recent 30-year period.
SFAS	Statement of Financial Accounting Standards.
Spot Market	The buying and selling of natural gas on a short-term basis, typically month-to-month.
Units of Measurement:
Bcf	Billion cubic feet of gas.
Mcf	Thousand cubic feet of gas.
MMcf	Million cubic feet of gas.
/d	Added to various units of measure to denote units per day.

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FORWARD-LOOKING STATEMENTS

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

• the effects of weather and other natural phenomena on operations and sales to customers;

• economic climate and growth in the geographic areas where we do business;

• environmental issues, including changes in the climate, and regulations;

• implementation of gas Customer Choice programs;

• implementation of gas utility restructuring in Michigan;

• employee relations;

• access to capital markets and capital market conditions and other financing efforts which can be affected by credit agency ratings;

• the timing and extent of changes in interest rates;

• the level of borrowings;

• changes in the cost of natural gas;

• effects of competition;

• impact of FERC and MPSC proceedings and regulations;

• changes in federal or state tax laws and their interpretations, including the code, regulations, rulings, court proceedings and audits;

• ability to recover costs through rate increases;

• property insurance;

• the cost of protecting assets against or damage due to terrorism; and

• changes in accounting standards and financial reporting regulations.

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

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PART I

Item 1 & 2. Business & Properties

DESCRIPTION

Michigan Consolidated Gas Company (MichCon or the Company) is a Michigan corporation organized in 1898. MichCon is an indirect, wholly-owned subsidiary of Enterprises, an exempt holding company under the Public Utility Holding Company Act of 1935, successor to MCN Energy. MichCon is a natural gas utility subject to regulation by the MPSC. MichCon is engaged in the purchase, storage, transmission and distribution of natural gas in the state of Michigan. MichCon also has subsidiaries involved in the gathering and transmission of natural gas in northern Michigan. MichCon operates one of the largest natural gas distribution and transmission systems in the United States and the largest in Michigan.

MichCon serves approximately 1.2 million residential, commercial and industrial customers located throughout Michigan. MichCon had approximately $2.4 billion in assets at December 31, 2002 and revenues of approximately $1.3 billion in 2002.

On May 31, 2001, DTE Energy completed the acquisition of MCN Energy. At that time, MCN Energy merged with Enterprises, with Enterprises being the surviving corporation. See Note 3 for a further discussion of the MCN Energy merger.

References in this report to “we”, “us”, and “our” are to MichCon.

A discussion of the services we provide, and the amount and percentage of revenue contributed from such services follows:

Revenue by Service
(in Thousands)	2002				2001				2000
Gas Sales	$	1,077,705	82.1	%	$	1,005,989	82.6	%	$	909,270	79.5	%
End User Transportation		122,272	9.3			101,788	8.4			117,116	10.2
Intermediate Transportation		48,522	3.7			45,659	3.7			52,577	4.6
Other		63,972	4.9			64,176	5.3			65,379	5.7
	$	1,312,471	100.0	%	$	1,217,612	100.0	%	$	1,144,342	100.0	%

• Gas Sales–Includes the sale and delivery of natural gas primarily to residential and small-volume commercial and industrial customers.

• End User Transportation–A gas delivery service provided primarily to large-volume commercial and industrial customers. Additionally, the service is provided to residential customers, and small-volume commercial and industrial customers who have elected to participate in our Customer Choice program. End user transportation customers purchase natural gas directly from producers or brokerage companies and utilize our pipeline network to transport the gas to their facilities or homes.

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• Intermediate Transportation–A gas delivery service provided to producers, brokers and other gas companies that own the natural gas, but are not the ultimate consumers. Intermediate transportation customers utilize our gathering and high-pressure transmission system to transport the gas to storage fields, processing plants, pipeline interconnections or other locations.

• Other–Includes revenues from providing appliance maintenance, facility development and other energy-related services.

We expect to achieve modest revenue growth through initiatives to expand our gas markets, our residential, commercial and industrial customer base, as well as by continuing to provide energy-related services that capitalize on our expertise, capabilities and efficient systems.

Our operations are not dependent upon a limited number of customers, and the loss of any one or a few customers is not reasonably likely to have a material adverse effect on MichCon.

Our gas sales, end user transportation and intermediate transportation volumes, revenues and net income are impacted by weather. Given the seasonal nature of the business, revenues and net income are concentrated in the first and fourth quarters of the calendar year. By the end of the first quarter, the heating season is largely over, and we typically realize substantially reduced revenues and earnings in the second quarter and losses in the third quarter.

We obtain our natural gas supply from various sources in different geographic areas (the Gulf Coast, the Mid-Continent, Canada and Michigan) under agreements that vary in both pricing and terms. Because of our geographic diversity of supply and our 124 Bcf of storage capacity, we are able to reliably meet our supply requirements.

We have purchase commitments of approximately 140 billion cubic feet (Bcf), or 89% of our normal 2003 gas supply requirement. We have entered into fixed-price contracts for approximately 97 Bcf or 62% of our expected 2003 supply requirements. The balance of the gas supply requirement is expected to be met by purchasing gas at market prices. At December 31, 2002, we owned and operated four natural gas storage fields in Michigan with a working storage capacity of approximately 124 Bcf. These facilities play an important role in providing reliable and cost-effective service to our customers. Generally, we use our storage capacity to supplement our supply during the winter months, replacing the gas in April through October when demand and prices are historically at lower levels. The use of storage capacity also allows us to lower our peak-day entitlements, thereby reducing interstate pipeline charges. Our gas distribution system has a planned maximum daily send-out capacity of 3.0 Bcf, with approximately 56% of the volume coming from underground storage for 2002. Gas costs are recovered through the gas cost recovery (GCR) mechanism.

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Following is a listing of our sources of gas supply:

		2002			2001			2000
Gas Supply (Bcf)
Long Term
	Citygate suppliers		70.8			76.5			73.5
	Interstate pipeline suppliers		80.1			77.6			56.1
	Canadian pipeline suppliers		28.5			28.2			28.0
Spot Market			8.5			1.7			1.2
Exchange Gas Receipts (Deliveries)			0.8			(0.6	)		(1.0	)
Gas From (To) Storage			(11.1	)		19.6			24.5
			177.6			203.0			182.3

We have long-term firm transportation agreements expiring on various dates through 2011 with ANR Pipeline Company (ANR), Panhandle Eastern Pipeline Company (Panhandle), Viking Gas Transmission Company (Viking) and Great Lakes Gas Transmission Limited Partnership (Great Lakes). The ANR capacity delivers 153.5 MMcf/d of supply sourced from the Gulf Coast, 41.5 MMcf/d sourced from the Midcontinent and 50 MMcf/d from Canada. Viking transports the 50 MMcf/d of Canadian supply to the ANR system for delivery to us. Panhandle transports 2 MMcf/d of Gulf Coast supply from the ANR system for delivery to us and 40 MMcf/Day from the Mid-Continent production area to our system. Additional Canadian supplies of 30 MMcf/d are delivered through firm transport agreements with Great Lakes.

ANR will transport for us up to 245 million cubic feet per day (MMcf/d) of supply through October 2003. Effective in November 2003, 100 MMcf/Day of this capacity is due to expire. We intend to replace this capacity through a competitive bid process among several reliable transport service gas supply providers.

We have supply contracts with independent Michigan producers, which expire on various dates through 2007. Many of these contracts tie prices to spot market indices coupled with transportation rates.

REGULATION

We are subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to rates, recovery of certain costs, including the costs of regulatory assets, conditions of service, accounting and other operating-related matters. We are subject to the requirements of other regulatory agencies with respect to safety, the environment and health.

In the late 1990’s, the MPSC began an initiative designed to give all of Michigan’s natural gas customers added choices and the opportunity to benefit from lower gas costs resulting from competition. In 1999, the MPSC approved a comprehensive, experimental three-year gas Customer Choice program that allowed an increasing number of customers to purchase natural gas from suppliers other than their local utility. The local utility would continue to transport the natural gas supply to the customers’ facilities, thereby retaining distribution margins. In December 2001, the MPSC issued an order that continues the gas Customer Choice program on a permanent and expanding basis beginning with the conclusion of the three-year temporary program on March 31, 2002. Under the expanded program, which began April 1, 2002, up to approximately 40% of our customers could elect to purchase gas from suppliers other than MichCon. Beginning in April 2003, up to approximately 60% of customers could participate and

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beginning April 2004, all 1.2 million of our gas customers could choose to participate. We will continue to transport and deliver the gas to the participating customers’ premises at prices that generate favorable margins.

Under the December 2001 MPSC order, we returned to a GCR mechanism in January 2002 upon termination of the temporary Gas Sales Program. The GCR permits us to pass the cost of natural gas to our customers. Under the Gas Sales Program, the MPSC suspended the GCR mechanism and our sales rates included a gas commodity component that was fixed at $2.95 per thousand cubic feet (Mcf). Under this program, we incurred commodity price risk associated with our ability to secure gas supplies at prices less than $2.95 per Mcf. Beginning in January 2002, our gas sales rates include a gas commodity component designed to recover our actual gas costs.

In November 2002, the MPSC requested Michigan gas and electric utilities to justify why their retail rates should not be lowered due to potential personal property tax reductions. We have responded and await further MPSC action.

For additional information regarding our regulatory environment, see Note 5 - Regulatory Matters.

PROPERTIES

We own distribution, transmission and storage properties and facilities that are all located in the state of Michigan.

At December 31, 2002, our distribution system included 17,774 miles of distribution mains, 1,136,863 service lines and 1,241,516 active meters. We own 2,581 miles of transmission lines that deliver natural gas to the distribution districts and interconnect our storage fields with the sources of supply and the market areas. We own properties relating to four underground natural gas storage fields with an aggregate working gas storage capacity of approximately 124 Bcf.

Substantially all of our property is subject to the lien of our Indenture of Mortgage and Deed of Trust under which our First Mortgage Bonds are issued. Some properties are being fully utilized, and new properties are being added to meet the expansion requirements of existing areas. Our capital investments for 2002 totaled $90 million, which compares with $111 million in 2001 and $118 million in 2000.

Our subsidiaries own a 67-mile gathering pipeline that transports natural gas and natural gas liquids from reserves in east-central Michigan to natural gas processing plants in northern Michigan and 134 miles of gathering lines and a 2,400 horsepower compressor station located in northern Michigan. Other MichCon subsidiaries have a 46% interest in a partnership that owns lateral lines related to the 67-mile gathering pipeline and an 83% interest in an additional 32-miles of gathering pipelines in northern Michigan. We lease a portion of our pipeline system to the Vector Pipeline Partnership through a capital lease arrangement (Note 10).

STRATEGY & COMPETITION

We generate approximately 95% of our revenues from providing gas sales, and end user and intermediate transportation services. We continue to take steps to become the preferred provider of natural gas and high-value energy services within Michigan in order to achieve competitive financial results. We expect modest growth and to control costs in order to provide customers high-quality service at competitive prices. To accomplish this, we continue to position ourselves to respond to changes in regulation and

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increased competition by reducing our cost of operations, maintaining a safe and reliable system for customers, and focusing on meeting the needs of the marketplace.

Competition in the gas sales market primarily involves other natural gas providers, and alternative fuels such as electricity, propane and, to a lesser degree, oil and wood.

Other natural gas providers — As previously discussed, we are operating under the gas Customer Choice program that allows our customers to purchase natural gas from other suppliers. As a result of MichCon returning to a GCR mechanism in January 2002, we do not profit from selling gas. We continue to transport and deliver gas to customers who choose to purchase gas from other suppliers thereby retaining favorable margins.

Alternative fuels — Natural gas continues to be the preferred space and water-heating fuel for Michigan residences and businesses. Developers in our service territories select natural gas in new construction because of the convenience, cleanliness and relative price advantage compared to propane, fuel oil and other alternative fuels.

The primary focus of competition in the end user transportation market is cost and reliability. Some large commercial and industrial customers have the ability to switch to alternative fuel sources such as coal, electricity, oil and steam. If these customers were to choose an alternative fuel source, they would not have a need for our end user transportation service. In addition, some of these customers could bypass our pipeline system and have their gas delivered directly from an interstate pipeline. However, price differentials must be sufficient to offset the costs, risks and loss of service flexibility associated with fuel switching or bypass. Since 1988, only one MichCon industrial customer has bypassed our distribution system. We compete against alternative fuel sources by providing competitive pricing and reliable service, supported by our extensive storage capacity.

Our extensive transmission pipeline system has enabled us to develop a 500 to 600 Bcf annual market for transportation services for Michigan gas producers, marketers, distribution companies and other pipeline companies. We operate in a pivotal geographic location with links to major interstate pipelines that reach markets elsewhere in the Midwest, the eastern United States and eastern Canada. Michigan gas production has also increased significantly over the past several years, resulting in a growing demand by gas producers and brokers for intermediate transportation services.

ENVIRONMENTAL MATTERS

We are subject to extensive environmental regulation. Additional costs may result as the effects of various chemicals on the environment are studied and governmental regulations are developed and implemented. We expect to continue recovering environmental costs related to utility operations through rates charged to our customers. Greater details on environmental issues are provided in the following Notes to the Consolidated Financial Statements:

Note	Title
5	Regulatory Matters
12	Commitments and Contingencies

Prior to the construction of major natural gas pipelines, gas for heating and other uses was manufactured from processes involving coal, coke or oil. We own, or previously owned, 16 such former manufactured gas plant (MGP) sites. Investigations have revealed contamination related to the by-products of gas manufacturing at each site. We are remediating eight of the former MGP sites and are conducting more

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extensive investigations at three of the sites. We have received Michigan Department of Environmental Quality (MDEQ) closure of one site and a determination that we are not a responsible party for two other sites. While we cannot make any assurances, we believe that a cost deferral and rate recovery mechanism approved by the MPSC will prevent these costs from having a material adverse impact on our results of operations.

RISK FACTORS

There are various risks associated with the operations of our business. To provide a framework to understand our operating environment, we are providing a brief explanation of the more significant risks associated with our business. Although we have tried to identify and discuss key risk factors, others could emerge in the future. Each of the following risks could affect our performance.

Weather – Weather significantly affects our operations. Deviations from normal cold weather conditions affect our earnings and cash flow. Mild temperatures can result in decreased utilization of our assets, lowering income and cash flow.

Regional and national economic conditions – Our business follows the economic cycles of the customers we serve. Should national or regional economic conditions decline, reduced volumes of gas we supply will result in decreased earnings and cash flow.

Environmental laws and liability – We are subject to numerous environmental regulations. Compliance with these regulations can significantly increase capital spending and operating expenses. These laws and regulations require us to seek a variety of environmental licenses, permits, inspections, and other regulatory approvals. The regulatory environment is subject to significant change, and therefore we cannot predict future issues.

Additionally, we may become a responsible party for environmental clean up at sites identified by a regulatory body. We cannot predict with certainty the amount and timing of future expenditures related to environmental matters because of the difficulty of estimating clean up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.

Rate regulation – We operate in a regulated industry. Our rates are set by the MPSC and cannot be increased without their authorization. We may be impacted by new regulations or interpretations by the MPSC or other regulatory bodies. New legislation, regulations or interpretations could change how our business operates, impact our ability to recover costs through rate increases or may require us to incur additional expenses.

Competition – Deregulation and restructuring in the gas industry, including the customer choice program, could result in increased competition and unrecovered costs that could affect the financial condition, results of operations or cash flows of our regulated business.

Supply and price of raw materials – Our access to natural gas supplies is critical to ensure reliability of service for our regulated gas customers.

Labor relations – Unions represent a majority of our employees. A union choosing to strike as a negotiating tactic could have an impact on our business.

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Access to capital markets and interest rates – Our ability to access capital markets is important to operate our business. Heightened concerns about the energy industry, the level of borrowing by other energy companies and the market as a whole could limit our access to capital markets. Changes in interest rates could increase our borrowing costs.

Property tax reform – We are one of the largest payers of property taxes in the state of Michigan. Should the legislature change how schools are financed, we could face increased property taxes on our Michigan facilities.

Credit ratings – Increased scrutiny of the energy industry and regulatory changes could result in credit agencies reexamining our credit rating. A change in our rating could restrict our ability to access capital markets at attractive rates and increase our borrowing costs.

Property insurance – While we seek to adequately insure our property, catastrophic damage as a result of acts of God, terrorism, war or a combination of significant unforeseen items occurring at one time could impact our operations and economic losses might not be covered in full by insurance.

Terrorism – Damage to downstream infrastructure or our own assets by terrorist groups would impact our operations. We may be required to increase security or assist other energy companies if terrorists were to strike their energy facilities.

EMPLOYEES

We had 2,246 employees at December 31, 2002, of which 1,508 were represented by unions.

Item 3. Legal Proceedings

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

Note	Title
5	Regulatory Matters
12	Commitments and Contingencies

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Item 4. Submission of Matters to a Vote of Security Holders

Omitted per general instruction I (2) (c) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

PART II

Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters

All of the 10,300,000 issued and outstanding shares of common stock of MichCon, par value $1 per share, are indirectly owned by DTE Energy, and constitute 100% of the voting securities of MichCon. Therefore, no market exists for our common stock.

We did not pay cash dividends in 2002. We paid cash dividends on our common stock of $75 million in 2001 and $100 million in 2000.

Item 6. Selected Financial Data

Omitted per general instruction I (2) (a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

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Item 7. Management’s Narrative Analysis of Results of Operations

The Results of Operations discussion for MichCon is presented in accordance with General Instruction I (2) (a) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

Certain losses reflected in the accompanying consolidated financial statements have been eliminated at DTE Energy as a result of purchase accounting adjustments.

We had earnings of $20.3 million in 2002, compared to losses of $41.1 million in 2001. As subsequently discussed, the comparison was impacted by $103.4 million ($67.2 million net of taxes) of merger and restructuring charges recorded in 2001. Excluding merger and restructuring costs, 2001 earnings were $26.1 million, a decline of $86.1 million from 2000 results reflecting lower gross margins and higher operating costs.

Increase (Decrease) in Income Compared to Prior Year
	2002			2001
(in Millions)
Operating revenues	$	94.9		$	73.3
Cost of gas		(91.5	)		(156.2	)
Gross margin		3.4			(82.9	)
Operation and maintenance		20.4			(44.5	)
Depreciation, depletion and amortization		6.0			(9.1	)
Taxes other than income		4.9			5.0
Merger and restructuring charges		103.4			(99.4	)
Property write-down and contract loss		(47.8	)		—
Other income and deductions		9.4			(1.0	)
Income tax provision		(38.2	)		81.2
Net income	$	61.5		$	(150.7	)

Operating revenues increased $94.9 million in 2002 and increased $73.3 million in 2001. As subsequently discussed, operating revenues reflect the operations of our Gas Sales Program and the impact of weather, which was warmer than normal in 2002 and 2001. Our three-year Gas Sales Program is part of its Regulatory Reform Plan (Note 5) which ended in December 2001.

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		2002		2001		2000
(in Millions)
Operating Revenues
	Gas Sales	$	1,077.7	$	1,006.0	$	909.3
	End User Transportation		122.3		101.8		117.1
			1,200.0		1,107.8		1,026.4
	Intermediate Transportation		48.5		45.7		52.6
	Other		64.0		64.1		65.3
		$	1,312.5	$	1,217.6	$	1,144.3
Gas Markets (Bcf)
	Gas Sales		170.2		199.8		178.9
	End User Transportation		169.5		149.2		163.5
			339.7		349.0		342.4
	Intermediate Transportation		492.1		565.1		598.9
			831.8		914.1		941.3

		2002			2001			2000
Effect of Weather on Gas Markets and Earnings
Percentage Warmer Than Normal			(5.8	)%		(12.1	)%		(5.5	)%
Decrease From Normal in:
	Gas markets (in Bcf)		(12.6	)		(26.4	)		(12.4	)
	Net income (in Millions)	$	(11.1	)	$	(23.3	)	$	(11.7	)

Gas sales and end user transportation revenues in total increased $92.2 million in 2002 and $81.4 million in 2001. Revenues in 2002 reflect an increase in the gas commodity component of sales rates. During 2001 we operated under the Gas Sales Program in which the gas commodity component of our sales rates was fixed at $2.95 per thousand cubic feet (Mcf). In January 2002, the Gas Sales Program ended and we returned to a gas cost recovery mechanism (GCR) that allows for the recovery of reasonably and prudently incurred gas costs. Our sales rates included a gas commodity component of $3.62 per Mcf for January 2002 and $4.38 per Mcf for the remainder of 2002 compared to $2.95 per Mcf in 2001 and 2000. Revenues in 2002 were adversely affected by a $26.5 million accrual for the possible disallowance of gas cost in the 2002 GCR reconciliation case. See Note 17. Higher revenues in 2001 reflect more customers choosing to purchase their gas from us rather than other gas suppliers. There were approximately 190,000 customers participating in the gas Customer Choice program in 2002, compared to approximately 30,000 customers in 2001. Higher gas sales in 2001 were impacted by sales to off system customers allowed under the Gas Sales Program. Revenues were also impacted by weather that was warmer than normal.

End user transportation volumes and revenues also reflect deliveries associated with a varying number of customers participating in the Customer Choice program. Customers participating in this program purchase gas from other suppliers, while we continue to deliver the gas to their premises.

Upon returning to the GCR mechanism in January 2002, we have no commodity price risk associated with our prudently incurred gas costs. Accordingly, no margin was earned from selling gas in 2002. Margins generated from providing end user transportation services were not affected by the return to a GCR.

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Intermediate transportation revenues increased $2.8 million in 2002 and decreased $6.9 million in 2001, whereas intermediate transportation deliveries decreased 73.0 Bcf in 2002 and decreased 33.8 Bcf in 2001. A significant portion of the volume decrease was due to weather, slightly offset by a volume increase attributable to customers who pay a fixed fee for intermediate transportation capacity regardless of actual usage. Although volumes associated with these fixed-fee customers may vary, the related revenues are not affected.

Cost of gas is affected by variations in sales volumes, cost of purchased gas and related transportation costs, and the effects of any permanent liquidation of inventory gas. Cost of gas sold increased $91.5 million in 2002 and $156.2 million in 2001 primarily due to prices paid for gas supply and the impact in 2001 of a reduction in inventory gas. The average cost of gas sold increased $1.05 per Mcf (32%) and increased $0.49 per Mcf (17%) for 2002 and 2001, respectively. We recorded the benefits of a 19.6 Bcf inventory liquidation in 2001. The inventory liquidation was priced at $0.38 per Mcf compared to an average gas purchase rate in 2001 of $3.61 per Mcf. The effect of the inventory liquidation lowered cost of gas for 2001 by $63.2 million.

Operation and maintenance expenses decreased $20.4 million in 2002 and increased $44.5 million in 2001. The 2002 decrease was due primarily to lower accruals for injuries and damages and costs allocated from DTE Energy corporate for corporate support services, partially offset by higher uncollectible accounts expense. The 2001 increase is due to costs allocated from DTE Energy corporate for corporate support services, higher employee medical costs and accruals for injuries and damages.

Depreciation, depletion and amortization decreased $6.0 million in 2002 and increased $9.1 million in 2001. The 2001 increase was impacted by an adjustment of $8 million recorded in settlement in an MPSC proceeding that required a MichCon subsidiary to record additional depreciation expense.

Taxes other than income decreased $4.9 million in 2002 and decreased $5.0 million in 2001. The improvement is attributed to lower Michigan Single Business Taxes. The comparisons also reflect an adjustment in property tax expense resulting from a change in method of calculating the taxable value of personal property subject to taxation by local taxing jurisdictions.

Merger and restructuring charges were not incurred in 2002 and increased $99.4 million in 2001. Merger costs associated with the DTE Energy acquisition of MCN Energy consist primarily of system integration, relocation, legal, accounting and consulting costs (Notes 3 and 4). Restructuring charges consist of charges associated with a work force reduction plan.

Property write-down and contract loss totaled $47.8 million in 2002 due to a $33.2 million loss from the planned sale of our former headquarters and a $14.6 million charge related to the termination of a contract for computer services.

Other income and deductions decreased $9.4 million in 2002 and increased $1.0 million in 2001. The variance is primarily due to a $9.3 million loss in 2001 from our 33% to 50% interests in a series of partnerships that own a residential community on the Detroit riverfront (Harbortown). Partially offsetting the decrease for the 2002 period were higher interest costs. The 2001 increase in interest income of $6.4 million results from leasing a portion of our pipeline system to the Vector Pipeline Partnership through a capital lease arrangement that began in December 2000 (Note 10).

14

Income taxes increased $38.2 million in 2002 and decreased $81.2 million in 2001 (Note 6). Income tax comparisons were affected by variations in pre-tax earnings and tax adjustments recorded upon filing our tax returns.

CAPITAL RESOURCES AND LIQUIDITY

Cash and Cash Equivalents
(in Millions)		Year Ended December 31
		2002			2001			2000
Cash Flow From (Used For)
	Operating activities	$	44.6		$	58.5		$	227.4
	Investing activities		(85.1	)		(103.4	)		(122.6	)
	Financing activities		43.6			36.2			(101.8	)
Net Increase (Decrease) in Cash and Cash Equivalents		$	3.1		$	(8.7	)	$	3.0

Operating Activities

Net cash from operating activities decreased $13.9 million in 2002 due to higher working capital requirements, partially offset by higher net income, after adjusting for noncash items (depreciation, depletion and amortization, property write-down and contract losses and deferred taxes). The higher working capital requirements primarily reflect a significant increase in gas inventories due to management’s decision to utilize storage gas during 2001 that resulted in a gas inventory decrement during the 2001 calendar year. Net cash from operating activities decreased $168.9 million in 2001 due to lower net income, after adjusting for noncash items, partially offset by lower working capital requirements.

Investing Activities

Net cash used for investing activities decreased $18.3 million in 2002 and $19.2 million in 2001, respectively, reflecting declines in capital expenditures.

Financing Activities

Net cash related to financing activities increased $7.4 million in 2002 and increased $138.0 million in 2001. The 2002 increase reflects a $200 million capital contribution by our parent company which was offset by the repayment of short-term borrowings. The 2001 increase reflects the issuance of long-term debt which was offset by a $75 million dividend payment.

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

15

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Prior to the reinstatement of the GCR mechanism in January 2002, our primary market risk arose from fluctuations in natural gas prices. We managed such natural gas price risk by entering into fixed-price contracts for a large portion of our expected supply requirements. If we did not enter into these fixed-price supply contracts, our exposure to such risk would have been substantially higher. See Note 11 – Financial and Other Derivative Instruments.”

Interest Rate Risk

We currently have market risk from fluctuations in interest rates. We manage interest rate risk through the use of various derivative instruments and limit the use of such instruments to hedging activities. If we did not use derivative instruments, our exposure to such risk would be higher. We are subject to interest rate risk in connection with the issuance of fixed- and variable-rate debt. In order to manage interest costs, we use interest rate swap agreements to exchange fixed- and variable-rate interest payment obligations over the life of the agreements without exchange of the underlying principal amounts. Our exposure to interest rate risk arises primarily from changes in U.S. Treasury rates, commercial paper rates and London Inter-Bank Offered Rates (LIBOR).

At December 31, 2002 and 2001, we had interest rate swap agreements with notional principal amounts totaling $40 million and $80 million and a weighted average remaining life of 2.4 and 1.9 years, respectively. The notional principal amounts are used solely to calculate amounts to be paid or received under the interest rate swap agreements and approximate the principal amount of the underlying debt being hedged.

A sensitivity analysis model was used to calculate the fair values of our debt and interest rate swaps, utilizing applicable forward interest rates in effect at December 31, 2002. The sensitivity analysis involved increasing and decreasing the forward rates by a hypothetical 10% and calculating the resulting change in the fair values or cash flows of the interest rate sensitive instruments.

The results of the sensitivity model calculations follow:

	2002					2001
	Assuming			Assuming		Assuming			Assuming
	a 10%			a 10%		a 10%			a 10%
	Increase in			Decrease in		Increase in			Decrease in
	Prices/Rates			Prices/Rates		Prices/Rates			Prices/Rates
Market Risk (in Millions)
Interest Rate Sensitive
Debt: Fixed rate	$	(27.7	)	$	30.3	$	(23.6	)	$	26.2
Swaps: Pay variable/receive fixed	$	(0.2	)	$	0.2	$	(0.5	)	$	0.5

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Credit Risk

We sell gas to numerous companies operating in the steel, automotive, energy and retail industries. During 2002 and 2001, a number of customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code, including certain Enron Corporation affiliates. We regularly review contingent matters relating to purchase and sale contracts and record provisions for amounts considered probable of loss. We believe our previously accrued amounts are adequate for probable losses. The final resolution of these matters is not expected to have a material effect on our financial statements in the period they are resolved.

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Item 8. Financial Statements and Supplementary Data

	Page
Independent Auditors’ Report		19
Consolidated Statement of Operations		20
Consolidated Statement of Financial Position		21
Consolidated Statement of Cash Flows		22
Consolidated Statement of Retained Earnings		23
Notes to Consolidated Financial Statements		24
Financial Statement Schedule – Schedule II – Valuation and Qualifying Accounts		47

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INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Shareholder of
Michigan Consolidated Gas Company

We have audited the consolidated statement of financial position of Michigan Consolidated Gas Company and subsidiaries (the “Company”) as of December 31, 2002 and 2001 and the related consolidated statements of operations, cash flows, and retained earnings for each of the three years in the period ended December 31, 2002. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15. These financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Michigan Consolidated Gas Company and subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
 

/s/ DELOITTE & TOUCHE LLP

Detroit, Michigan
February 11, 2003 (March 12, 2003 as to Note 17)

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MICHIGAN CONSOLIDATED GAS COMPANY
CONSOLIDATED STATEMENT OF OPERATIONS

		Year Ended December 31
		2002			2001			2000
(in Thousands)
Operating Revenues		$	1,312,471		$	1,217,612		$	1,144,342
Operating Expenses
	Cost of gas		754,222			662,699			506,522
	Operation and maintenance		277,209			297,639			253,117
	Depreciation, depletion and amortization		106,790			112,794			103,650
	Taxes other than income		51,308			56,250			61,260
	Merger and restructuring charges		—			103,447			4,058
	Property write-down and contract loss		47,844			—			—
			1,237,373			1,232,829			928,607
Operating Income (Loss)			75,098			(15,217	)		215,735
Other Income and Deductions
	Interest on long-term debt		49,647			46,293			48,320
	Other interest expense		9,325			10,600			11,501
	Interest income		(10,406	)		(9,694	)		(3,247	)
	Loss on investment in joint venture		—			9,342			—
	Equity in earnings of joint ventures		(2,555	)		(2,593	)		(3,453	)
	Other		(3,260	)		(1,841	)		(1,873	)
			42,751			52,107			51,248
Income (Loss) Before Income Taxes			32,347			(67,324	)		164,487
Income Tax Provision (Benefit) (Note 6)			12,018			(26,200	)		54,953
Net Income (Loss)		$	20,329		$	(41,124	)	$	109,534

See Notes to Consolidated Financial Statements.

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MICHIGAN CONSOLIDATED GAS COMPANY
CONSOLIDATED STATEMENT OF FINANCIAL POSITION

				December 31
				2002		2001
(in Thousands)
ASSETS
	Current Assets
		Cash and cash equivalents		$	7,025	$	3,929
		Accounts receivable
			Customer (less allowance for doubtful accounts of $26,894 and $21,428, respectively)		156,476		143,660
			Accrued unbilled revenues		116,061		110,300
			Other		73,233		99,458
		Accrued gas cost recovery revenue			21,706		14,401
		Inventories
			Gas		54,623		6,178
			Material and supplies		14,460		15,013
		Other			53,193		16,053
					496,777		408,992
	Property, Plant and Equipment				3,108,176		3,065,415
		Less accumulated depreciation, depletion and amortization			1,722,746		1,626,015
					1,385,430		1,439,400
	Other Assets
		Other investments			79,355		76,231
		Notes receivable			84,220		85,176
		Regulatory assets			42,459		43,356
		Prepaid benefit costs and due from affiliate			291,834		229,530
		Other			31,194		30,108
					529,062		464,401
				$	2,411,269	$	2,312,793
LIABILITIES AND SHAREHOLDER’S EQUITY
	Current Liabilities
		Accounts payable		$	104,457	$	137,181
		Short-term borrowings			122,918		256,862
		Current portion of long-term debt, including capital leases			98,588		21,130
		Federal income, property and other taxes payable			32,391		172
		Regulatory liabilities			29,696		—
		Other			83,015		74,772
					471,065		490,117
	Other Liabilities
		Deferred income taxes			129,912		124,828
		Regulatory liabilities			142,198		144,172
		Unamortized investment tax credit			22,100		24,129
		Accrued postretirement benefit costs			76,765		69,981
		Accrued environmental costs			17,535		20,743
		Other			34,165		40,062
					422,675		423,915
	Long-term debt, including capital lease obligations				678,101		778,577
	Commitments and Contingencies (Notes 5 and 12)
	Shareholder’s Equity
		Common stock, $1 par value, 15,100,000 shares authorized, 10,300,000 shares issued and outstanding			10,300		10,300
		Additional paid in capital			430,643		231,728
		Retained earnings			398,485		378,156
					839,428		620,184
				$	2,411,269	$	2,312,793

See Notes to Consolidated Financial Statements.

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MICHIGAN CONSOLIDATED GAS COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS

					Year Ended December 31
					2002			2001			2000
(in Thousands)
Operating Activities
	Net income (loss)				$	20,329		$	(41,124	)	$	109,534
	Adjustments to reconcile net income to net cash from operating activities:
			Depreciation, depletion and amortization			115,691			122,641			113,429
			Property write-down and contract loss			34,861			—			—
			Deferred income taxes and investment tax credit, net			5,354			(25,875	)		31,378
			Changes in assets and liabilities:
				Accounts receivable, net		13,409			(85,672	)		(15,671	)
				Accrued unbilled revenues		(5,760	)		25,165			(36,599	)
				Inventories		(47,892	)		6,568			60,564
				Prepaid benefit costs and due from affiliate		(62,304	)		(15,463	)		(57,777	)
				Accounts payable		(32,724	)		39,122			4,808
				Federal income, property and other taxes payable		32,219			(15,176	)		(3,779	)
				Other		(28,596	)		48,307			21,502
	Net cash from operating activities					44,587			58,493			227,389
Investing Activities
	Capital expenditures					(90,224	)		(111,219	)		(117,645	)
	Other					5,163			7,806			(5,013	)
		Net cash used for investing activities				(85,061	)		(103,413	)		(122,658	)
Financing Activities
	Capital contribution by parent company					200,000			—			—
	Issuance of long-term debt					—			198,382			—
	Redemption of long-term debt					(22,486	)		(65,385	)		(42,740	)
	Short-term borrowings, net					(133,944	)		(21,821	)		40,977
	Dividends paid					—			(75,000	)		(100,000	)
		Net cash from (used for) financing activities				43,570			36,176			(101,763	)
Net Increase (Decrease) in Cash and Cash Equivalents						3,096			(8,744	)		2,968
Cash and Cash Equivalents at Beginning of Period						3,929			12,673			9,705
Cash and Cash Equivalents at End of Period					$	7,025		$	3,929		$	12,673
Supplementary Cash Flow Information
			Interest paid (excluding interest capitalized)		$	58,741		$	58,249		$	59,466
			Income taxes paid			—			(3,142	)		22,959

See Notes to Consolidated Financial Statements.

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MICHIGAN CONSOLIDATED GAS COMPANY
CONSOLIDATED STATEMENT OF RETAINED EARNINGS

	Year Ended December 31
	2002		2001			2000
(in Thousands)
Balance – beginning of period	$	378,156	$	494,648		$	494,803
Net income (loss)		20,329		(41,124	)		109,534
Common stock dividends declared		—		(75,368	)		(109,689	)
Balance – end of period	$	398,485	$	378,156		$	494,648

See Notes to Consolidated Financial Statements.

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MICHIGAN CONSOLIDATED GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1– SIGNIFICANT ACCOUNTING POLICIES

Corporate Structure

Michigan Consolidated Gas Company (MichCon) is a public utility engaged in the purchase, storage, transmission and distribution of natural gas in the state of Michigan. MichCon is subject to the accounting requirements of and rate regulation by the Michigan Public Service Commission (MPSC) with respect to the distribution and intrastate transportation of natural gas. The major services provided by MichCon are gas sales, end user transportation and intermediate transportation. MichCon serves more than 1.2 million residential, commercial and industrial customers throughout Michigan. MichCon’s non-regulated operations are not significant. MichCon is an indirect, wholly owned subsidiary of DTE Enterprises Inc. (Enterprises), an exempt holding company under the Public Utility Holding Company Act of 1935.

References in this report to “we”, “us”, and “our” are to MichCon.

Principles of Consolidation

We consolidate all majority owned subsidiaries and investments in entities in which we have controlling influence. Non-majority owned investments are accounted for using the equity method when the company is able to influence the operating policies of the investee. Non-majority owned investments include investments in limited liability companies, partnerships or joint ventures. When we do not influence the operating policies of an investee, the cost method is used.

Basis of Presentation

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

We reclassified some prior year balances to match the 2002 financial statement presentation.

Revenues and Cost of Gas

Revenues from the transportation and storage of natural gas are recognized as services are provided. We record revenues for gas services provided but unbilled at the end of each month. Through December 2001, our rates included a component for cost of gas sold that was fixed at $2.95 per thousand cubic feet (Mcf). In 2002, we implemented a gas cost recovery (GCR) mechanism that will recover the prudent and reasonable cost of gas sold subject to annual proceedings before the MPSC. See Notes 5 and 17.

Cash Equivalents

For purposes of the Consolidated Statement of Cash Flows, we consider investments purchased with a maturity of three months or less to be cash equivalents.

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Inventories

Materials and supplies are valued at average cost. Gas inventory is determined using the last-in, first-out (LIFO) method. At December 31, 2002, the replacement cost of gas remaining in storage exceeded the $54.6 million LIFO cost by $186.5 million. During 2001, we liquidated 19.6 Bcf of prior years’ LIFO layers at an average cost of $0.38 per thousand cubic feet. Our average purchase rate in 2001 was $3.23 per Mcf higher than the average LIFO liquidation rate. Applying LIFO cost in valuing the liquidation, as opposed to using the average gas purchase rate, decreased 2001 cost of gas by $63.2 million and increased earnings by $41.1 million, net of taxes.

Property, Retirement and Maintenance, and Depreciation and Depletion

Property is stated at cost and includes construction-related labor and materials. The cost of properties retired plus removal costs, less salvage are charged to accumulated depreciation. Expenditures for maintenance and repairs are charged to expense when incurred.

We base depreciation provisions on straight-line and units of production rates approved by the MPSC. Unit of production depreciation and depletion is used for certain production and transmission property. Our composite depreciation rate was 3.6% in 2002, 3.9% in 2001 and 3.6% in 2000.

The average estimated useful life for gas distribution and transmission property was 26 years and 29 years, respectively, at December 31, 2002.

Allowance for Funds Used during Construction

We capitalize an allowance for both debt and equity funds used during construction in the cost of major additions to utility plant. The total amount capitalized was $1,992,000, $1,202,000 and $1,722,000 in 2002, 2001 and 2000, respectively.

Long-Lived Assets

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

Software Costs

We capitalize the cost of software developed for internal use. These costs are amortized on a straight-line basis over five years. Amortization begins when the software project is complete.

Excise and Sales Taxes

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

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Deferred Debt Costs

The costs related to the issuance of long-term debt are amortized over the life of each debt issue. In accordance with MPSC regulations, the unamortized discount, premium and expense related to debt redeemed with a refinancing are amortized over the life of the replacement issue.

See the following notes for other accounting policies impacting our financial statements:

Note	Title
2	New Accounting Pronouncements
5	Regulatory Matters
6	Income Taxes
11	Financial and Other Derivative Instruments
13	Retirement Benefits and Trusteed Assets

NOTE 2 – NEW ACCOUNTING PRONOUNCEMENTS

Derivatives

Effective January 1, 2001, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. SFAS No. 133 establishes accounting and reporting standards for derivative instruments and for hedging activities. SFAS No. 133 requires that companies recognize all derivatives as either assets or liabilities measured at fair value on the statement of financial position. SFAS No. 133 provides an exception for certain contracts that qualify as “normal purchases and sales.” To qualify for this exception, certain criteria must be met, including a high probability the contract will result in physical delivery. See Note 11 – Financial and Other Derivative Instruments for additional information.

Goodwill and Other Intangible Assets

Effective January 1, 2002, we adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” which addresses the financial accounting and reporting standards for the acquisition of intangible assets outside of a business combination and for goodwill and other intangible assets subsequent to their acquisition. As of the date of adoption, we had no recorded goodwill.

In connection with the adoption of SFAS No. 142, we also reassessed the useful lives and the classification of identifiable intangible assets and determined that they continue to be appropriate. Our intangible assets consist primarily of software and are subject to amortization. Intangible assets amortization expense was $10 million in 2002 and $9 million in 2001. There were no material acquisitions of intangible assets during 2002. The gross carrying amount and accumulated amortization of intangible assets at December 31, 2002 were $160 million and $45 million, respectively. Amortization expense of intangible assets is estimated to be $9 million annually for 2003 through 2007.

Asset Retirement Obligations

On January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which requires the fair value of an asset retirement obligation be recognized in the period in which it is

26

incurred. It will apply to legal obligations associated with the retirement of long-lived assets resulting from the acquisition, construction, development and (or) the normal operation of a long-lived asset. When a new liability is recorded, an entity will capitalize the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The adoption of SFAS No. 143 is expected to have an immaterial impact on the consolidated financial statements.

SFAS No. 143 also requires the quantification of the estimated cost of removal obligations, arising from other than legal obligations, which have been accrued through depreciation charges. At January 1, 2003 we estimate that we had approximately $400 million of previously accrued asset removal costs related to our regulated operations, for other than legal obligations, included in accumulated depreciation

Long-Lived Assets

SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.” This statement establishes a single accounting model for long-lived assets to be disposed of by sale, whether previously held and used, or newly acquired. We adopted this statement on January 1, 2002, with no impact on the consolidated financial statements.

Reporting Gains and Losses from Extinguishment of Debt and Accounting for Leases

SFAS No. SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections,” eliminates SFAS No. 4 “Reporting Gains and Losses from Extinguishment of Debt” and allows for only those gains or loses on the extinguishment of debt that meet the criteria of extraordinary items to be treated as such in the financial statements. SFAS No. 145 also amends SFAS No. 13 “Accounting for Leases” to require sale-leaseback accounting for certain lease transactions. We adopted the provisions of this statement in 2002 with no impact on the consolidated financial statements.

Exit and Disposal Activities

SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” requires that the liability for costs associated with exit or disposal activities be recognized when incurred, rather than at the date of a commitment to an exit or disposal plan. Application of SFAS No. 146 is required prospectively for exit or disposal activities entered into on or after January 1, 2003.

Guarantor’s Accounting and Disclosure

FASB Interpretation No. 45 requires a guarantor to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. It also requires disclosure in interim and annual financial statements of its obligations under certain guarantees it has issued. The initial recognition and measurement provisions of Interpretation No. 45 are to be applied prospectively to guarantees issued or modified after December 31, 2002. The disclosure requirements are effective for financial statements for periods ending after December 15, 2002. We expect no impact on the consolidated financial statements upon adoption.

27

Consolidation of Variable Interest Entities

FASB Interpretation No. 46 requires variable interest entities, previously referred to as special-purpose entities or off-balance sheet structures, be consolidated by a company if that company is subject to a majority of the risk of loss from the entity’s activities or is entitled to receive a majority of the entity’s returns or both. The consolidation provisions of Interpretation No. 46 apply immediately to variable interest entities created after January 31, 2003 and to existing entities in the first fiscal year or interim period beginning after June 15, 2003. Certain disclosure provisions apply in financial statements issued after January 31, 2003. We expect no impact on the consolidated financial statements upon adoption.

NOTE 3 — MCN ENERGY ACQUISITION

On May 31, 2001, DTE Energy completed the acquisition of MCN Energy, our parent company, by acquiring all of its outstanding shares of common stock for a combination of cash and shares of DTE Energy common stock. MCN Energy was merged with and into Enterprises, the surviving corporation in the merger and a wholly-owned subsidiary of DTE Energy. The acquisition by DTE Energy was accounted for using the purchase method. The assets and liabilities included in our accompanying consolidated financial statements have not been adjusted to allocate the purchase price to their fair values. Certain losses reflected in the accompanying consolidated financial statements have been eliminated at DTE Energy as a result of purchase accounting adjustments.

NOTE 4 – MERGER AND RESTRUCTURING CHARGES

On May 31, 2001, DTE completed the acquisition of MCN Energy. We incurred the following costs:

(in Thousands)
	2001		2000
Merger related	$	22,486	$	4,058
Restructuring		80,961		—
Total pre-tax		103,447		4,058
Total net of tax	$	67,240	$	2,638

Merger related charges represent systems integration, relocation, legal, accounting and consulting costs. Restructuring charges were primarily associated with a work force reduction plan. The plan included early retirement incentives and voluntary separation agreements for 273 employees, primarily in overlapping corporate support areas. Approximately $25 million of the merger and restructuring charges were paid as of December 31, 2001 and remaining benefit payments have been or will be paid from retirement plans.

NOTE 5 — REGULATORY MATTERS

Regulation

We are subject to the regulatory jurisdiction of the MPSC, which issues orders pertaining to rates, recovery of certain costs, including the costs of regulatory assets, conditions of service, accounting and operating-related matters.

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Our operations meet the criteria of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” This accounting standard recognizes the cost-based ratemaking process, which results in differences in the application of generally accepted accounting principles between regulated and non-regulated businesses. SFAS No. 71 requires the recording of regulatory assets and liabilities for certain transactions that would have been treated as revenue and expense in non-regulated businesses. Continued applicability of SFAS No. 71 requires that rates be designed to recover specific costs of providing regulated services and be charged to and collected from customers. Management believes that currently available facts support the continued application of SFAS No. 71. Future regulatory changes or changes in the competitive environment could result in the company discontinuing the application of SFAS No. 71 for some or all of its business and require the write-off of the portion of any regulatory asset or liability that was no longer probable of recovery through regulated rates.

Regulatory Assets and Liabilities

The following are the balances of the regulatory assets and liabilities as of December 31:

(in Thousands)		2002		2001
Regulatory Assets:
	Deferred environmental costs	$	26,990	$	26,920
	Unamortized loss on retirement of debt		15,469		16,436
	Accrued gas cost recovery revenue		21,706		14,401
		$	64,165	$	57,757
Regulatory Liabilities:
	Tax benefits amortizable to customers	$	142,198	$	144,172
	Accrued 2002 GCR potential disallowance		26,500		—
	Other		3,196		—
		$	171,894	$	144,172

Tax benefits amortizable to customers represents the net revenue equivalent of the difference in property-related accumulated deferred income taxes computed in accordance with SFAS No. 109, “Accounting for Income Taxes,” as compared to the amounts previously reflected in setting utility rates. This amount is primarily due to current tax rates being lower than the rates in effect when the original deferred taxes were recorded and because of temporary differences, including accumulated investment tax credits, for which deferred income taxes were not previously recorded in setting utility rates. These net tax benefits are being amortized, in accordance with the regulatory treatment, over the life of the related plant as the temporary differences reverse.

As discussed in Note 17, on March 12, 2003, the MPSC ordered MichCon to reduce revenues by $26.5 million for purposes of calculating the 2002 GCR expense in the 2002 GCR reconciliation proceeding. Although we have reflected a $26.5 million reduction in revenues for 2002 and a regulatory liability at December 31, 2002, a final determination of actual 2002 GCR revenue and expenses including any disallowances or adjustments will be decided in MichCon's 2002 GCR reconciliation case.

Gas Industry Restructuring

Through December 2001, we were operating under an MPSC-approved Regulatory Reform Plan, which included a comprehensive experimental three-year Customer Choice program, a Gas Sales Program and an income sharing mechanism. We returned to a GCR mechanism in January 2002 when the Gas Sales Program expired. Under the GCR mechanism, the gas commodity component of our gas sales rates is designed to recover the actual costs of gas purchases. In December 2001, the MPSC issued an order that permitted us to implement GCR factors up to $3.62 per Mcf for January 2002 billings and up to $4.38 per Mcf for the remainder of 2002. The order also allowed us to recognize a regulatory asset of approximately $14 million representing the difference between the $4.38 factor and the $3.62 factor for

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volumes that were unbilled at December 31, 2001. The regulatory asset will be subject to the 2002 GCR reconciliation process. As of December 31, 2002, we have accrued a $21.7 million regulatory asset representing the under-recovery of actual gas costs incurred. In July 2002, in response to a petition for rehearing filed by the Michigan Attorney General, the MPSC directed the parties to address our implementation of the December 2001 order and the impact of that implementation on rates charged to our customers. Also, in July 2002, an MPSC Administrative Law Judge (ALJ) issued a Proposal for Decision on our 2002 GCR plan case. In that decision the ALJ recommended adoption of the MPSC Staff’s proposed $26.5 million reduction in gas cost due to our decision to utilize storage gas during 2001 that resulted in a gas inventory decrement for the 2001 calendar year. See Note 17 for information concerning a March 2003 MPSC order in this matter.

In September 2002, we filed for approval of our 2003 GCR Plan with a GCR factor of $4.14 per Mcf to be effective in monthly bills beginning with the January 2003 billing month. In January 2003, we filed and received a temporary order (effective for February 2003 through December 2003 billing months) raising the GCR factor to $4.575 due to the increase in the price of gas.

In December 2001, the MPSC also approved our application for a voluntary, expanded permanent gas Customer Choice program, which would replace the experimental program that expired in March 2002. Effective April 2002, up to 40% of our customers could elect to purchase gas from other suppliers. Effective April 2003, up to 60% of customers would be eligible and by April 2004, all of our 1.2 million customers can participate in the program. The MPSC also approved the use of deferred accounting for the recovery of implementation costs of the gas Customer Choice program. As of December 2002, approximately 190,000 customers are participating in the gas Customer Choice program.

As previously mentioned, we were operating under a Regulatory Reform Plan through December 2001, which included an income sharing mechanism. The income sharing mechanism allowed customers to share in profits when actual returns on equity from utility operations exceed predetermined thresholds. Based on the MPSC approved formula, we believe that no income sharing is required in 2001. In July 2002, the MPSC ordered a hearing be held to determine the appropriate treatment of $766,000 of pipeline refunds we received during 2001. We do not agree with the MPSC Staff’s position that this amount should be refunded to customers.

In November 2002, the MPSC requested Michigan gas and electric utilities to justify why their retail rates should not be lowered due to potential personal property tax reductions. We have responded and await further MPSC action.

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

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NOTE 6 — INCOME TAXES

We are part of the consolidated federal income tax return of DTE Energy. Our federal income tax expense is determined on an individual company basis with no allocation of tax benefits or expenses from other affiliates of DTE Energy.

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

(in Thousands, except effective tax rate)	2002			2001			2000
Effective federal income tax rate		37.2	%		38.9	%		33.2	%
Income tax expense at 35% statutory rate	$	11,321		$	(23,589	)	$	57,570
Investment tax credit		(2,029	)		(1,738	)		(1,911	)
Depreciation		(1,283	)		3,131			3,150
Other-net		4,009			(4,004	)		(3,856	)
Total	$	12,018		$	(26,200	)	$	54,953

Components of income tax expense (benefit) were as follows:

(in Thousands)	2002		2001			2000
Current federal and other income tax expense (benefit)	$	8,637	$	(6,297	)	$	23,575
Deferred federal income tax expense (benefit)		3,381		(19,903	)		31,378
Total	$	12,018	$	(26,200	)	$	54,953

Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences between the tax basis of assets or liabilities and the reported amounts in the financial statements. Deferred tax assets and liabilities are classified as current or noncurrent according to the classification of the related assets or liabilities. Deferred tax assets and liabilities not related to assets or liabilities are classified according to the expected reversal date of the temporary differences.

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

(in Thousands)	2002			2001
Property	$	(54,336	)	$	(52,324	)
Property taxes		(7,119	)		(7,231	)
Pension and employee benefits		(45,719	)		(43,963	)
Other		(23,066	)		(19,728	)
	$	(130,240	)	$	(123,246	)
Deferred income tax liabilities	$	(383,183	)	$	(171,145	)
Deferred income tax assets		252,943			47,899
	$	(130,240	)	$	(123,246	)

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NOTE 7 – PREFERRED AND PREFERENCE SECURITIES

At December 31, 2002, MichCon had 7 million shares of preferred stock with a par value of $1 per share and 4 million shares of preference stock with a par value of $1 per share authorized, with no shares issued.

NOTE 8 – LONG-TERM DEBT

Our long-term debt outstanding and weighted average interest rates of debt outstanding at December 31 was:

(in Thousands)			2002		2001
First Mortgage Bonds, interest payable semi-annually
		6.72% series due 2003	$	—	$	4,150
		6.8% series due 2003		—		15,850
		7.15% series due 2006		40,000		40,000
		7.21% series due 2007		30,000		30,000
		7.06% series due 2012		40,000		40,000
		8.25% series due 2014		80,000		80,000
		7.6% series due 2017		14,604		14,645
		7.5% series due 2020		28,411		28,513
		6.75% series due 2023		14,176		14,802
		7% series due 2025		40,000		40,000
Remarketable securities, interest payable semi-annually
		6.2% series due 2038		—		75,000
		6.45% series due 2038		75,000		75,000
Senior notes, interest payable semi-annually
		6.125% series due 2008		200,000		200,000
Senior notes, interest payable quarterly
		6.85% series due 2038		52,354		52,640
		6.85% series due 2039		55,000		55,000
Other long-term debt				5,155		8,896
Net unamortized premium				1,890		1,998
Long-term capital lease obligations				1,511		2,083
	Total		$	678,101	$	778,577

In 2002, we repaid $17.3 million of first mortgage bonds that matured in May 2002.

In 2001, we issued $200 million of 6.125% senior secured notes, due September 2008. These notes are “fall-away mortgage” debt and, as such, are secured debt as long as our other first mortgage bonds are outstanding and become senior unsecured debt thereafter. We have the option to redeem the notes at any time using a redemption price of par or the present value of the remaining payments of principal and interest discounted to the redemption date on a semiannual basis at the adjusted treasury rate plus 25 basis points.

In 2001, we redeemed $40 million of 9.5% first mortgage bonds, which were due in 2021.

In 1998, we issued a total of $150 million of remarketable debt securities with various interest rates.

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These securities are “fall-away mortgage” debt and are structured such that the interest rates of the issues can be reset at various remarketing dates over the life of the debt. The initial remarketing dates are in June 2003 and 2008. We received option premiums in return for granting options to the underwriters to reset the interest rate for a period of ten years at the initial remarketing dates. The option premiums received, net of financing costs incurred, totaled $3,052,000 and are being amortized to income over the initial interest and corresponding option periods. If the underwriters elect not to exercise their reset options, the securities become subject to the remarketing feature or we may redeem them at par. If we cannot agree on an interest rate with the remarketing agent or the remarketing agent is unable to remarket the securities, we will be required to repurchase the securities at their principal amounts. Amounts that will be remarketed in 2003 are included in the current portion of long-term debt.

Our non-utility subsidiaries have amounts outstanding under a nonrecourse credit agreement. Under the terms of the agreement, certain alternative variable interest rates are available at the borrowers’ option during the life of the agreement. Quarterly principal payments are made, with a final installment due November 2005. The loan is secured by a pledge of stock of the borrowers and a security interest in certain of their assets. We may be required to support the credit agreement through limited capital contributions to the subsidiaries if certain cash flow and operating targets are not met. At December 31, 2002 and 2001, $7.4 million and $10.8 million were outstanding at weighted average interest rates of 2.1% and 2.5%, respectively.

We have a variable interest rate swap agreement with notional principal amounts aggregating $40 million in connection with its first mortgage bonds. Swap agreements of $40 million through May 2005 have reduced the average cost of the related debt from 7.1% to 2.3% for the year ended December 31, 2002.

Substantially all of the net utility property of MichCon is subject to the lien of a Mortgage and Deed of Trust (Mortgage). Should we fail to timely pay our indebtedness under the Mortgage, such failure will create cross defaults in substantially all of our indebtedness.

Maturities and sinking fund requirements during the next five years for long-term debt outstanding at December 31, 2002 are $98 million in 2003, $3 million in 2004, $2 million in 2005, $40 million in 2006 and $30 million in 2007.

NOTE 9 – SHORT-TERM CREDIT ARRANGEMENTS AND BORROWINGS

In October 2002, we entered into a $200 million 364-day revolving facility and a $100 million three-year revolving facility. These credit facilities can be used for general corporate purposes, but are primarily intended to provide liquidity for our commercial paper program. Important aspects of these agreements require us to maintain a debt to total capitalization ratio of no more than .65 to 1, and an “earnings before interest, taxes, depreciation and amortization” to interest ratio of no less than 2 to 1.

Commercial paper and borrowings outstanding at December 31, 2002 and 2001 totaled $120.1 million and $254.8 million at weighted average interest rates of 1.5% and 2.1%, respectively.

NOTE 10 – CAPITAL AND OPERATING LEASES

Lessee - We lease certain property (principally a warehouse, office building and parking structure) under capital lease arrangements expiring at various dates to 2006, with renewal options extending beyond that date. Portions of the office building and parking structure are subleased to various tenants. Long-term capital lease obligations are not significant.

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Operating lease payments for the years ended December 31, 2002, 2001 and 2000 were $2.1 million, $2.3 million and $2.2 million, respectively.

Lessor – We lease a portion of our pipeline system to the Vector Pipeline Partnership through a capital lease contract that expires in 2020, with renewal options extending for five years. The components of the net investment in the capital lease at December 31, 2002 were as follows:

(in Thousands)
2003	$	9,000
2004		9,000
2005		9,000
2006		9,000
2007		9,000
Thereafter		116,250
Total minimum future lease receipts		161,250
Residual value of leased pipeline		39,742
Less — unearned income		(117,252	)
Net investment in direct financing lease		83,740
Less — current portion		(956	)
	$	82,784

NOTE 11 – FINANCIAL AND OTHER DERIVATIVE INSTRUMENTS

In 1998, FASB issued SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS No. 133, establishes accounting and reporting standards for derivative instruments and hedging activities. Listed below are important SFAS No. 133 requirements:

• All derivative instruments must be recognized as assets or liabilities and measured at fair value, unless they meet the “normal purchases and sales” exemption.

• The accounting for changes in fair value depends upon the purpose of the derivative instrument and whether it is designated as a hedge and qualifies for hedge accounting.

• Special accounting is allowed for a derivative instrument qualifying as a hedge and designated as a hedge for the variability of cash flow associated with a forecasted transaction. Gain or loss associated with the effective portion of the hedge is recorded in other comprehensive income. The ineffective portion is recorded to earnings. Amounts reported in other comprehensive income will be reclassified into net income when the forecasted transaction affects earnings.

• If a cash flow hedge is discontinued because it is unlikely the forecasted transaction will not occur, net gains or losses are immediately recorded into earnings.

• Special accounting is allowed for a derivative instrument qualifying as a hedge and designated as a hedge of the changes in fair value of an existing asset, liability or firm commitment. Gain or loss on the hedging instrument is recorded into earnings. The gain or loss on the underlying asset, liability or firm commitment is also recorded into earnings.

SFAS No. 133 requires that as of the date of initial adoption, the difference between the fair value of derivative instruments and the previous carrying amount of those derivatives to be reported in net income or other comprehensive income as the cumulative effect of a change in accounting principle. The cumulative effect of adopting SFAS No. 133 was not material.

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Our primary market risk exposure is associated with commodity prices and interest rates. We have risk management policies to monitor and decrease market risks. We use derivative instruments to manage some of the exposure.

RISK MANAGEMENT ACTIVITIES

Credit Risk

We are exposed to credit risk if customers or counterparties do not comply with their contractual obligations. We maintain credit policies that significantly minimize overall credit risk. These policies include an evaluation of potential customers’ and counterparties’ financial condition, credit rating, collateral requirements or other credit enhancements such as letters of credit or guarantees. We use standardized agreements that allow the netting of positive and negative transactions associated with a single counterparty.

Interest Rate Risk

In order to manage interest costs, we have interest rate swap agreements to exchange fixed- and variable-rate interest payment obligations over the life of the agreements without the exchange of the underlying principal amounts. While the swaps are effective in managing our interest costs, they do not qualify for hedge accounting under SFAS No. 133. Accordingly, the interest rate swaps are recorded at fair value and shown within “Other Deferred Assets or Liabilities” in the consolidated statement of financial position. Unrealized gains or losses resulting from marking to market these swaps are recognized as an adjustment to interest expense in the consolidated statement of operations. Furthermore, SFAS No. 133 required adjusting the carrying value of the related debt that substantially offsets the transition adjustment from marking to market the interest rate swaps. The adjustment to debt will be accreted to interest expense over the life of the related swaps.

At December 31, 2002 and 2001, we had interest rate swap agreements with notional principal amounts totaling $40 million and $80 million and a weighted average remaining life of 2.4 and 1.9 years, respectively. The notional principal amounts are used solely to calculate amounts to be paid or received under the interest rate swap agreements and approximate the principal amount of the underlying debt being hedged.

Commodity Price Risk

We have firm-priced contracts for a substantial portion of our expected gas supply requirements though 2003. These contracts qualify for the “normal purchases” exception under SFAS No.133. Accordingly, we do not account for such contracts as derivatives.

FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value of financial instruments is determined by using various market data and other valuation techniques. The estimated fair value of total long-term debt at December 31, 2002 and 2001 was $858.3 million and $799.6 million, respectively, compared to the carrying amount of $774.6 million and $793.7 million, respectively.

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NOTE 12 — COMMITMENTS AND CONTINGENCIES

Personal Property Taxes

MichCon and other Michigan utilities have asserted that Michigan’s valuation tables result in the substantial overvaluation of utility personal property. Valuation tables established by the Michigan State Tax Commission (STC) are used to determine the taxable value of personal property based on the property’s age. In November 1999, the STC approved new valuation tables that more accurately recognize the value of a utility’s personal property. The new tables became effective in 2000 and are currently used to calculate property tax expense. However, several local taxing jurisdictions have taken legal action attempting to prevent the STC from implementing the new valuation tables and have continued to prepare assessments based on the superseded tables. The legal actions regarding the appropriateness of the new tables were before the Michigan Tax Tribunal (MTT) which, in April 2002 issued its decision essentially affirming the validity of the STC’s new tables. In June 2002, petitioners in the case filed an appeal of the MTT’s decision with the Michigan Court of Appeals. The Michigan Court of Appeals has not yet issued a decision on this appeal.

We record property tax expense based on the new tables. We will seek to apply the new tables retroactively and to ultimately settle the pending tax appeals related to 1997 through 1999. This is a solution supported by the STC in the past. The legal action, along with possible additional appeals by local taxing jurisdictions, is expected to delay any recoveries.

Environmental Matters

Former manufactured gas plant sites – Prior to the construction of major natural gas pipelines, gas for heating and other uses was manufactured from processes involving coal, coke or oil. We own, or previously owned, 16 such former manufactured gas plant (MGP) sites.

During the mid-1980’s, we conducted preliminary environmental investigations at former MGP sites, and some contamination related to the by-products of gas manufacturing was discovered at each site. The existence of these sites and the results of the environmental investigations have been reported to the Michigan Department of Environmental Quality (MDEQ). None of these former MGP sites is on the National Priorities List prepared by the U.S. Environmental Protection Agency (EPA).

We completed the administrative proceeding before the EPA regarding one of the former MGP sites. The site received closure from the EPA in 2002. We are remediating seven of the former MGP sites and conducting more extensive investigations at five other former MGP sites. In 1998, we received state closure of one of the former MGP sites. Additionally, the MDEQ has determined with respect to two other former MGP sites that we are not a responsible party for the purpose of assessing remediation expenditures. In September 2001, we were advised of one additional MGP site for which we have some responsibility. After review of the extent of the necessary environmental clean-up required, remediation costs for this site are not expected to exceed $500,000.

In 1984, we established an $11.7 million reserve for environmental investigation and remediation. During 1993, we received MPSC approval of a cost deferral and rate recovery mechanism for investigation and remediation costs incurred at former MGP sites in excess of this reserve.

We employed outside consultants to evaluate remediation alternatives for these sites, to assist in estimating its potential liabilities and to review its archived insurance policies. The findings of these investigations indicate that the estimated total expenditures for investigation and remediation activities for these sites could range from $30 million to $170 million based on undiscounted 1995 costs. As a

36

result of these studies, we recorded an additional liability and a corresponding regulatory asset of $32 million during 1995.

During 2002, 2001 and 2000, we spent $3.2 million, $4.8 million and $1.3 million, respectively, investigating and remediating these former MGP sites. At December 31, 2002, the reserve balance was $22.2 million, of which $4.7 million was classified as current. Any significant change in assumptions, such as remediation techniques, nature and extent of contamination and regulatory requirements, could impact the estimate of remedial action costs for the sites and, therefore, have an effect on our financial position and cash flows. However, we believe the cost deferral and rate recovery mechanism approved by the MPSC will prevent environmental costs from having a material adverse impact on our results of operations.

Formerly owned storage field – In 1998, we received written notification from ANR Pipeline Company (ANR), alleging that we have responsibility for a portion of the costs associated with responding to environmental conditions present at a natural gas storage field in Michigan currently owned and operated by an affiliate of ANR. We formerly owned at least some portion of the natural gas storage field. ANR’s allegations are being evaluated to determine whether and to what extent, if any, we may have legal responsibility for these costs. Management does not believe this matter will have a material adverse impact on our financial statements.

Commitments

To ensure a reliable supply of natural gas at competitive prices, we have entered into long-term purchase and transportation contracts with various suppliers and producers. In general, purchases are under fixed price and volume contracts or formulas based on market prices. We have firm purchase commitments through 2007 for approximately 182 Bcf of gas. We expect that sales, based on warmer-than-normal weather, will exceed our minimum purchase commitments. We have long-term transportation contracts with various pipeline companies expiring on various dates through the year 2011. We are committed to pay demand charges of approximately $36 million during 2003 related to firm transportation agreements.

We expect that our 2003 capital investments will approximate $110 million. Certain commitments have been made in connection with such capital expenditures.

One of our subsidiaries and an unaffiliated corporation have formed a series of partnerships engaged in the construction and development of a residential community on the Detroit riverfront (Harbortown). One of the partnerships obtained $12 million of tax-exempt financing due June 2004 through the Michigan State Housing Development Authority. Both partners and their parent corporations have issued guaranties for the full amount of this financing, and each parent corporation has agreed to reimburse the other for 50% of any payments made as a result of these guaranties.

Other Contingencies

We sell gas to numerous companies operating in the steel, automotive, energy and retail industries. During 2002 and 2001, a number of customers have filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code, including certain Enron Corporation affiliates. We regularly review contingent matters relating to purchase and sale contracts and record provisions for amounts considered probable of loss. We believe our previously accrued amounts are adequate for probable losses. The final resolution of these matters is not expected to have a material effect on our financial statements in the period they are resolved.

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

NOTE 13 — RETIREMENT BENEFITS AND TRUSTEED ASSETS

Pension Plan Benefits

We sponsor a defined benefit retirement plan for MichCon union employees and participate in a defined benefit retirement plan for other DTE Energy union and nonunion employees. The plans are noncontributory, cover substantially all employees and provide retirement benefits to MichCon employees based on the employee’s years of benefit service, average final compensation and age at retirement. Currently these plans meet the full funding requirements of the Internal Revenue Code. Accordingly, no contributions for the 2002, 2001 or 2000 plan years were made.

Effective December 31, 2001, the MCN Energy Group Retirement Plan, that covered nonunion employees, merged into the DTE Energy Company Retirement Plan. Detroit Edison operates as the sponsor of the merged plan, which is treated as a multiemployer plan from the affiliates’ perspective. Accordingly, the liabilities and assets associated with this Plan are no longer reflected in the tables below, and the associated prepaid pension asset of $188 million is now reflected as an amount due from affiliate at December 31, 2002. We are allocated income or an expense each year as a result of our participation in the DTE Energy Retirement Plan. The annual income for 2002 was $43.5 million. The annual cost for 2001 was $4.4 million, which included a $52.5 million charge for special termination benefits and a $6.2 million curtailment gain associated with the early retirement window offered during the year.

Net pension credit for the years ended December 31 includes the following components:

(in Thousands)		2002(1)			2001(1)			2000(2)
Service Cost		$	3,539		$	3,398		$	9,500
Interest Cost			13,745			13,784			35,896
Expected Return on Plan Assets			(32,598	)		(32,772	)		(86,724	)
Amortization of
	Net gain		(3,730	)		(4,440	)		(11,200	)
	Prior service cost		1,580			1,580			1,711
	Net transition asset		(1,373	)		(1,373	)		(4,821	)
Curtailments/Settlement Recognition			—			—			(2,140	)
Net Pension Credit		$	(18,837	)	$	(19,823	)	$	(57,778	)

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The following table reconciles the obligations, assets and funded status of the plans as well as the amounts recognized as prepaid pension cost in the consolidated statement of financial position at December 31:

(in Thousands)		2002(1)			2001(1)
Accumulated Benefit Obligation at the End of the Period		$	194,795		$	166,068
Projected Benefit Obligation at the Beginning of the Period		$	182,493		$	485,433
Service Cost			3,539			3,398
Interest Cost			13,745			13,784
Plan Amendments			—			5,000
Actuarial (Gain) Loss			25,791			(11,457	)
Benefits Paid			(13,568	)		(16,335	)
Nonunion liabilities allocated to multiemployer plan			—			(297,330	)
Projected Benefit Obligation at the End of the Period		$	212,000		$	182,493
Plan Assets at Fair Value at the Beginning of the Period		$	318,756		$	989,967
Actual Return on Plan Assets			(31,573	)		(11,842	)
Benefits Paid			(13,568	)		(16,335	)
Nonunion liabilities allocated to multiemployer plan			—			(643,034	)
Plan Assets at Fair Value at the End of the Period		$	273,615		$	318,756
Funded Status of the Plans		$	61,615		$	136,263
Unrecognized
	Net (gain) loss		29,136			(64,556	)
	Prior service cost		13,828			15,408
	Net transition asset		(739	)		(2,112	)
Prepaid Pension Cost		$	103,840		$	85,003
(1) MichCon union plan only
(2) MichCon union and nonunion plans

In determining the actuarial present value of the projected benefit obligation, the discount rate was 6.75% for 2002, 7.25% for 2001 and 7.5% for 2000. The rate of increase in future compensation levels used was 4% for 2002 and 2001 and 5% for 2000. The expected long-term rate of return on plan assets was 9.0% for 2002 and 9.5% for 2001 and 2000.

We also sponsor a defined contribution retirement savings plan for union employees, the MichCon Investment and Stock Ownership Plan, and participate in a defined contribution plan for nonunion employees. Effective December 31, 2001, the MCN Energy Group Savings and Stock Ownership Plan, that covered nonunion employees of MichCon, MCN Energy and MCN Energy Enterprises, merged into the DTE Energy Company Savings and Stock Ownership Plan. Participation in one of these plans is available to substantially all union and nonunion employees. We match employee contributions up to certain predefined limits based upon the definition of eligible compensation, employee contributions and years of credited service. The cost of these plans was $4.4 million in 2002, $4.7 million in 2001, and $4.8 million in 2000.

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Other Postretirement Benefits

We provide certain postretirement health care and life insurance benefits for retired employees who may become eligible for these benefits while working for us. Our policy is to fund certain trusts to meet our postretirement benefit obligations. Separate qualified Voluntary Employees’ Beneficiary Association (VEBA) trusts exist for union and nonunion employees. No contributions were made to the VEBA trusts in 2002, 2001 or 2000.

Net postretirement cost for the years ended December 31 includes the following components:

(in Thousands)		2002			2001			2000
Service Cost		$	4,485		$	3,016		$	3,950
Interest Cost			18,117			18,270			18,779
Expected Return on Plan Assets			(16,821	)		(18,489	)		(16,319	)
Amortization of
	Net gain		(5,511	)		(6,268	)		(5,364	)
	Prior service cost		770			—			—
	Net transition obligation		10,337			12,224			12,702
Special Termination Benefits (Note 3)			—			22,790			—
Curtailment/Settlement Recognition			—			5,285			—
Net Postretirement Cost		$	11,377		$	36,828		$	13,748

40

The following table reconciles the obligations, assets and funded status of the plans as well as the amounts recorded as accrued postretirement cost in the consolidated statement of financial position at December 31:

(in Thousands)		2002			2001
Accumulated Postretirement Benefit Obligation at the Beginning of the Period		$	254,864		$	239,351
Service Cost			4,485			3,016
Interest Cost			18,117			18,270
Actuarial Gain (Loss)			92,619			(5,809	)
Plan Amendments			—			(542	)
Special Termination Benefits (Note 3)			—			17,971
Benefits Paid			(18,345	)		(17,393	)
Accumulated Postretirement Benefit Obligation at the End of the Period		$	351,740		$	254,864
Plan Assets at Fair Value at the Beginning of the Period		$	148,780		$	192,749
Actual Return on Plan Assets			(21,676	)		(23,042	)
Benefits Paid			(16,456	)		(20,927	)
Plan Assets at Fair Value at the End of the Period		$	110,648		$	148,780
Funded Status of the Plans		$	(241,092	)	$	(106,084	)
Unrecognized
	Net (gain) loss		44,444			(100,946	)
	Prior service cost		8,474			(542	)
	Net transition obligation		111,409			140,294
Regular Benefits Made After Measurement Date			—			(2,703	)
Accrued Postretirement Liability		$	(76,765	)	$	(69,981	)

The discount rate used in determining the accumulated postretirement benefit obligation was 6.75% for 2002, 7.25% for 2001 and 7.5% for 2000. The expected long-term rate of return on plan assets was 9.2% for 2002 and 9.8% for 2001 and 2000.

Benefit costs were calculated assuming health care cost trend rates beginning at 10% for 2003 and decreasing to 5% in 2009 and thereafter for persons under age 65 and decreasing from 9% to 5% for persons age 65 and over. A one percentage point increase in the health care cost trend rates would have increased the aggregate of the service cost and interest cost components of benefit costs by $2.9 million. The accumulated benefit obligation would have increased by $29 million at December 31, 2002. A one percentage point decrease in the health care cost trend rates would have decreased the total of the service cost and interest cost components of benefit costs by $2.6 million and would have decreased the accumulated benefit obligation by $25.8 million at December 31, 2002.

In 2003, we amended our postretirement health care and life insurance plans to reduce benefits, modify eligibility criteria and increase retiree co-pays. The changes reduced the postretirement benefit obligation by $17 million and the expected 2003 postretirement costs by $4 million. The reduction in postretirement benefit obligation and costs is not reflected in the previous tables.

41

Grantor Trust

We maintain a Grantor Trust which invests in life insurance contracts and income securities. Employees and retirees have no right, title or interest in the assets of the Grantor Trust, and we can revoke the trust subject to providing the MPSC with prior notification.

NOTE 14 — RELATED PARTY TRANSACTIONS

We had transactions with affiliated companies to provide transportation and storage services and for the purchase natural gas. Under a service agreement with DTE Energy, we receive various tax, financial and legal services and provides construction, engineering, human resources, information technology and other services. The following is a summary of transactions with affiliated companies:

(in Thousands)		2002		2001		2000
Revenues
	Transportation and storage services	$	7,221	$	4,055	$	13,293
	Other services		1,884		3,041		4,558
	Interest		7		6		587
Costs
	Gas purchases		—		69,204		77,542
	Corporate expenses, merger costs and other services		68,301		72,956		19,017

Our accounts receivable from affiliated companies totaled $52.9 million and $12.9 million, and accounts payable to affiliated companies totaled $18.6 million and $36.2 million at December 31, 2002 and 2001, respectively. The 2001 increase in corporate expenses, merger costs and other services is due to costs allocated from DTE Energy corporate since the May 31, 2001 acquisition of MCN Energy.

In December 2002, we received a $200 million capital contribution from our parent company.

NOTE 15 – UNUSUAL CHARGES

Loss on Investment in Joint Ventures

During 2001, we recorded a $9.3 million pre-tax ($6.1 million net of taxes) loss from the expected sale of our 33% to 50% interests in a series of partnerships that own a residential community on the Detroit riverfront (Harbortown). The carrying value of the investment was reduced to fair value based on the estimated selling price less cost to sell. The sale of Harbortown is no longer expected to take place within one year, therefore, MichCon’s share of the partnerships’ results have been recognized.

Property Write-down

In June 2002, we recorded a $33.2 million pre-tax ($21.6 million net of taxes) loss from the planned sale of our former headquarters. The carrying value of the property was reduced to fair value based on the estimated selling price less cost to sell.

42

Contract Loss

In June 2002, we recorded a $14.6 million pre-tax ($9.5 million net of taxes) charge related to the termination of a contract for computer services with an unrelated third party.

NOTE 16 – SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Due to the seasonal nature of MichCon’s business, revenues and net income tend to be higher in the first and fourth quarters of the calendar year.

	First		Second			Third			Fourth
(in Thousands)	Quarter		Quarter			Quarter			Quarter		Year
2002
Operating Revenues	$	590,062	$	234,916		$	117,440		$	370,053	$	1,312,471
Operating Income (Loss)	$	96,650	$	(39,977	)	$	(23,823	)	$	42,248	$	75,098
Net Income (Loss)	$	54,129	$	(33,593	)	$	(19,898	)	$	19,691	$	20,329
2001
Operating Revenues	$	476,459	$	181,931		$	121,876		$	437,346	$	1,217,612
Operating Income (Loss)	$	160,104	$	(166,847	)	$	(54,366	)	$	45,892	$	(15,217	)
Net Income (Loss)	$	97,350	$	(120,144	)	$	(43,255	)	$	24,925	$	(41,124	)

NOTE 17 – SUBSEQUENT EVENT – REGULATORY MATTERS – GAS INDUSTRY RESTRUCTURING

As discussed in Note 5 – Regulatory Matters – Gas Industry Restructuring, in July 2002, an MPSC Administrative Law Judge (ALJ) issued a Proposal for Decision on MichCon’s 2002 GCR plan case. In that decision the ALJ recommended adoption of the MPSC Staff’s proposed $26.5 million reduction in gas cost due to MichCon’s decision to utilize storage gas during 2001 that resulted in a gas inventory decrement for the calendar year 2001. On March 12, 2003, the MPSC issued an order in MichCon’s 2002 GCR plan case. The MPSC ordered MichCon to reduce revenues by $26.5 million for purposes of calculating the 2002 GCR expense in the 2002 GCR reconciliation proceeding. Although we have reflected a $26.5 million reduction in revenues for 2002, a final determination of actual 2002 GCR revenue and expenses including any disallowances or adjustments will be decided in MichCon’s 2002 GCR reconciliation case.

43

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Part III

Item 10. Directors and Executive Officers of the Registrant

Item 11. Executive Compensation

Item 12. Security Ownership of Certain Beneficial Owners and Management

Item 13. Certain Relationships and Related Transactions

All omitted per general instruction I (2) (c) of Form 10-K for wholly owned subsidiaries (reduced disclosure format).

44

Part IV

Item 14. Controls and Procedures

(a)	Evaluation of disclosure controls and procedures
	MichCon’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of MichCon’s disclosure controls and procedures (as defined in Exchange Act Rules 13a – 14(c) and 15d – 14(d)) as of a date within 90 days before the filing of this annual report, and have concluded that, as of the evaluation date, such controls and procedures were effective at ensuring that required information will be disclosed on a timely basis in reports filed under the Exchange Act.
(b)	Changes in internal controls
	There have been no significant changes (including corrective actions with regard to significant deficiencies or material weaknesses) in MichCon’s internal controls or in other factors that could significantly affect these controls subsequent to the evaluation date referenced in paragraph (a) above.

Item 15. Exhibits, Financial Statement Schedule, and Reports On Form 8-K

 

(a) The following documents are filed as part of this Annual Report on Form 10-K.

(1)	Consolidated financial statements. See “Item 8 – Financial Statements and Supplementary Data.”
(2)	Financial statement schedule. See “Item 8 – Financial Statements and Supplementary Data.”
(3)	Exhibits.

Exhibit No.	Description
(i)	Exhibits filed herewith
12-3	Computation of Ratio of Earnings to Fixed Charges.
23-3	Consent of Deloitte & Touche LLP.
99-7	Chief Executive Officer Certification of Periodic Report.
99-8	Chief Financial Officer Certification of Periodic Report.

45

(ii)	Exhibits incorporated herein by reference
3-1	Restated Articles of Incorporation (Exhibit 3-1 to Form 10-Q for quarter ended March 31, 1993, file number 1-7310).
3-2	By-Laws (Exhibit 3-2 to Form 10-Q for quarter ended March 31, 1993, file number 1-7310).
4-1	Indenture between MichCon and Citibank, N.A. related to Senior Debt Securities dated as of June 1, 1998 (Exhibit 4-1 to Registration Statement No. 333-63370); First Supplemental Indenture dated as of June 18, 1998 (Exhibit 4-1 to June 18, 1998 Form 8-K); Second Supplemental Indenture dated as of June 9, 1999 (Exhibit 4-1 to June 4, 1999 Form 8-K); and Third Supplemental Indenture dated as of August 15, 2001 (Exhibit 4-2 to Form 10-Q for quarter ended September 30, 2001).
4-2	Indentures defining the rights of the holders of MichCon’s First Mortgage Bonds: MichCon’s Indenture of Mortgage and Deed of Trust dated as of March 1, 1944 (Exhibit 7-D to Registration Statement No. 2-5252); Twenty-ninth Supplemental Indenture, dated as of July 15, 1989, providing for the modification and restatement of the Indenture of Mortgage and Deed of Trust dated as of March 1, 1944; Thirtieth Supplemental Indenture, dated as of September 1, 1991 (Exhibit 4-1 to September 27, 1991 Form 8-K); Thirty-first Supplemental Indenture dates as of December 15, 1991 (Exhibit 4-1 to February 28, 1992 Form 8-K); Thirty-second Supplemental Indenture, dated as of January 5, 1993 (Exhibit 4-1 to 1992 Form 10-K); Thirty-third Supplemental Indenture, dated as of May 1, 1995 (Exhibit 4-2 to Registration Statement No. 33-59093); Thirty-fourth Supplemental Indenture dated as of November 1, 1996 (Exhibit 4-2 to Registration Statement No. 333-16285); Thirty-fifth Supplemental Indenture, dated as of June 18, 1998 (Exhibit 4-2 to June 18, 1998 Form 8-K); and Mortgage Supplemental Indenture dated as of August 15, 2001 (Exhibit 4-3 to Form 10-Q for quarter ended September 30, 2001).
10-1	MichCon Investment and Stock Ownership Plan, as amended (Exhibit 10-12 to 1998 Form 10-K).
99-1	364-Day Credit Agreement dated as of October 25, 2002 ($200 million) (Exhibit 99-3 to Form 10-Q for quarter ended September 30, 2002).
99-2	Three-Year Credit Agreement dated as of October 25, 2002 ($100 million) (Exhibit 99-4 to Form 10-Q for quarter ended September 30, 2001).

(b)  Reports on Form 8-K.
        None.

46

MICHIGAN CONSOLIDATED GAS COMPANY AND SUBSIDIARIES
SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS

(in Thousands)				Additions
				Provisions charged to					Deductions
									for Purposes
		Balance at					Utility Plant/		for Which the		Balance
		Beginning					Regulatory		Reserves Were		at End
Description		of Period		Income			Asset		Provided		of Period
Year Ended December 31, 2002
Reserve deducted from Assets in Consolidated Statement of Financial Position:
	Allowance for doubtful accounts	$	21,428	$	21,058		$	—	$	15,592	$	26,894
Reserve included in Current Liabilities — Other and in Accrued Environmental Costs in Consolidated Statement of Financial Position:
	Environmental	$	25,244	$	—		$	—	$	3,209	$	22,035
Reserve included in Other Liabilities — Other in Consolidated Statement of Financial Position:
	Injuries and damages	$	14,193	$	(3,511	)	$	310	$	2,543	$	8,449
Year Ended December 31, 2001
Reserve deducted from Assets in Consolidated Statement of Financial Position:
	Allowance for doubtful accounts	$	18,912	$	16,347		$	—	$	13,831	$	21,428
Reserve included in Current Liabilities — Other and in Accrued Environmental Costs in Consolidated Statement of Financial Position:
	Environmental	$	30,458	$	—		$	—	$	5,214	$	25,244
Reserve included in Other Liabilities — Other in Consolidated Statement of Financial Position:
	Injuries and damages	$	2,610	$	14,901		$	331	$	3,649	$	14,193
Year Ended December 31, 2000
Reserve deducted from Assets in Consolidated Statement of Financial Position:
	Allowance for doubtful accounts	$	17,777	$	14,148		$	—	$	13,013	$	18,912
Reserve included in Current Liabilities — Other and in Accrued Environmental Costs in Consolidated Statement of Financial Position:
	Environmental	$	31,368	$	—		$	350	$	1,260	$	30,458
Reserve included in Other Liabilities — Other in Consolidated Statement of Financial Position:
	Injuries and damages	$	2,726	$	2,341		$	627	$	3,084	$	2,610

47

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized.

	MICHIGAN CONSOLIDATED GAS COMPANY
			(Registrant)
Date: March 20, 2003	By:	/s/ DANIEL G. BRUDZYNSKI
			Daniel G. Brudzynski
			Chief Accounting Officer,
			Vice President and Controller

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

By	/s/ ANTHONY F. EARLEY, JR.
	Anthony F. Earley, Jr. Chairman of the Board, Chief Executive Officer, President and Chief Operating Officer
By	/s/ SUSAN M. BEALE
	Susan M. Beale Director, Vice President and Corporate Secretary
By	/s/ DAVID E. MEADOR
	David E. Meador Director

Date                      March 20, 2003

48

FORM 10-K CERTIFICATION

I, Anthony F. Earley, Jr., Chairman, President, Chief Executive and Chief Operating Officer of Michigan Consolidated Gas Company, certify that:

1.	I have reviewed this annual report on Form 10-K of Michigan Consolidated Gas Company;
2.	Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3.	Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4.	The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

(a)	designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
(b)	evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
(c)	presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

(a)	all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
(b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

/s/ ANTHONY F. EARLEY, JR.
Anthony F. Earley, Jr.
Chairman, President, Chief Executive and
Chief Operating Officer of
Michigan Consolidated Gas Company Date: March 20, 2003

49

FORM 10-K CERTIFICATION

I, David E. Meador, Senior Vice President and Chief Financial Officer of Michigan Consolidated Gas Company, certify that:

1.	I have reviewed this annual report on Form 10-K of Michigan Consolidated Gas Company;
2.	Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3.	Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4.	The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

(a)	designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
(b)	evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and
(c)	presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

(a)	all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and
(b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

/s/ DAVID E. MEADOR David E. Meador
Senior Vice President and
Chief Financial Officer of
Michigan Consolidated Gas Company Date: March 20, 2003

50

Exhibit Index

Exhibit No.	Description
(i)	Exhibits filed herewith
12-3	Computation of Ratio of Earnings to Fixed Charges.
23-3	Consent of Deloitte & Touche LLP.
99-7	Chief Executive Officer Certification of Periodic Report.
99-8	Chief Financial Officer Certification of Periodic Report.

EX-12.3 3 k74362exv12w3.txt COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES EXHIBIT 12-3 MICHIGAN CONSOLIDATED GAS COMPANY AND SUBSIDIARIES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES (THOUSANDS OF DOLLARS)

TWELVE MONTHS ENDED DECEMBER 31 ----------------------------------------------------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- EARNINGS Pre-tax income (loss) $ 32,449 $ (65,867) $ 163,915 $ 162,389 $ 114,619 Fixed charges 59,216 60,933 61,884 59,340 61,304 --------- ---------- --------- --------- --------- $ 91,665 $ (4,934) $ 225,799 $ 221,729 $ 175,923 ========= ========== ========= ========= ========= FIXED CHARGES Interest expensed $ 57,128 $ 55,305 $ 58,700 $ 55,891 $ 56,997 Interest capitalized 936 565 811 1,190 2,207 Amortization of debt discounts, premium and expense 1,844 1,588 1,121 1,144 955 Interest factor of rents 526 1,095 1,252 1,115 1,145 SFAS 133 Swap marked-to-market (1,218) 2,380 -- -- -- --------- ----------- --------- --------- --------- $ 59,216 $ 60,933 $ 61,884 $ 59,340 $ 61,304 ========= ========== ========= ========= ========= Ratio of Earnings to Fixed Charges 1.55 3.65 3.74 2.87 ========= ========= ========= ========= Coverage Deficiency (1) $ (66,432) ==========

(1) The earnings for the twelve-month period ended December 31, 2001 were not adequate to cover fixed charges. The amount of the deficiency was $66,432,000. The Ratio of Earnings to Fixed Charges excluding unusual charges would have been 1.62. EX-23.3 4 k74362exv23w3.txt CONSENT OF DELOITTE & TOUCHE LLP EXHIBIT 23-3 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement No. 333-63370 on Form S-3 of Michigan Consolidated Gas Company, of our report dated February 11, 2003 (March 12, 2003 as to Note 17), appearing in the Annual Report on Form 10-K of Michigan Consolidated Gas Company for the year ended December 31, 2002. Detroit, Michigan March 20, 2003 EX-99.7 5 k74362exv99w7.txt CHIEF EXECUTIVE OFFICER CERTIFICATION EXHIBIT 99-7 CERTIFICATION OF PERIODIC REPORT I, Anthony F. Earley, Jr., Chairman, President, Chief Executive and Chief Operating Officer of Michigan Consolidated Gas Company (the "Company"), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge and belief: (1) the Annual Report on Form 10-K of the Company for the annual period ended December 31, 2002 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: March 20, 2003 /s/ ANTHONY F. EARLEY, JR. ------------------------------------------- Anthony F. Earley, Jr. Chairman, President, Chief Executive and Chief Operating Officer of Michigan Consolidated Gas Company EX-99.8 6 k74362exv99w8.txt CHIEF FINANCIAL OFFICER CERTIFICATION EXHIBIT 99-8 CERTIFICATION OF PERIODIC REPORT I, David E. Meador, Senior Vice President and Chief Financial Officer of Michigan Consolidated Gas Company (the "Company"), certify, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best of my knowledge and belief: (1) the Annual Report on Form 10-K of the Company for the annual period ended December 31, 2002 (the "Report") fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: March 20, 2003 /s/ DAVID E. MEADOR ------------------------------------ David E. Meador Senior Vice President and Chief Financial Officer of Michigan Consolidated Gas Company -----END PRIVACY-ENHANCED MESSAGE-----

EX-12.3

                                                                    EXHIBIT 12-3


               MICHIGAN CONSOLIDATED GAS COMPANY AND SUBSIDIARIES
                COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
                             (THOUSANDS OF DOLLARS)



                                                          TWELVE MONTHS ENDED DECEMBER 31
                                               -----------------------------------------------------
                                                 2002         2001       2000       1999       1998
                                                 ----         ----       ----       ----       ----
                                                                              
EARNINGS
Pre-tax income (loss)                          $  32,449   $  (65,867) $ 163,915  $ 162,389  $ 114,619
Fixed charges                                     59,216       60,933     61,884     59,340     61,304
                                               ---------   ----------  ---------  ---------  ---------

                                               $  91,665   $   (4,934) $ 225,799  $ 221,729  $ 175,923
                                               =========   ==========  =========  =========  =========

FIXED CHARGES
Interest expensed                              $  57,128   $   55,305  $  58,700  $  55,891  $  56,997
Interest capitalized                                 936          565        811      1,190      2,207
Amortization of debt discounts, premium and
  expense                                          1,844        1,588      1,121      1,144        955
Interest factor of rents                             526        1,095      1,252      1,115      1,145
SFAS 133 Swap marked-to-market                    (1,218)       2,380         --         --         --
                                               ---------   ----------- ---------  ---------  ---------
                                               $  59,216   $   60,933  $  61,884  $  59,340  $  61,304
                                               =========   ==========  =========  =========  =========

Ratio of Earnings to Fixed Charges                  1.55                    3.65       3.74       2.87
                                               =========               =========  =========  =========

Coverage Deficiency (1)                                    $ (66,432)
                                                           ==========


(1)   The earnings for the twelve-month period ended December 31, 2001 were not
      adequate to cover fixed charges. The amount of the deficiency was
      $66,432,000. The Ratio of Earnings to Fixed Charges excluding unusual
      charges would have been 1.62.

EX-23.3

                                                                    EXHIBIT 23-3













INDEPENDENT AUDITORS' CONSENT


We consent to the incorporation by reference in Registration Statement No.
333-63370 on Form S-3 of Michigan Consolidated Gas Company, of our report dated
February 11, 2003 (March 12, 2003 as to Note 17), appearing in the Annual Report
on Form 10-K of Michigan Consolidated Gas Company for the year ended December
31, 2002.




Detroit, Michigan
March 20, 2003

EX-99.7

                                                                    EXHIBIT 99-7

                        CERTIFICATION OF PERIODIC REPORT

I, Anthony F. Earley, Jr., Chairman, President, Chief Executive and Chief
Operating Officer of Michigan Consolidated Gas Company (the "Company"), certify,
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section
1350, that to the best of my knowledge and belief:

(1)            the Annual Report on Form 10-K of the Company for the annual
               period ended December 31, 2002 (the "Report") fully complies with
               the requirements of Section 13(a) or 15(d) of the Securities
               Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2)            the information contained in the Report fairly presents, in all
               material respects, the financial condition and results of
               operations of the Company.

Date: March 20, 2003                         /s/ ANTHONY F. EARLEY, JR.
                                     -------------------------------------------
                                               Anthony F. Earley, Jr.
                                      Chairman, President, Chief Executive and
                                             Chief Operating Officer of
                                         Michigan Consolidated Gas Company

EX-99.8

                                                                    EXHIBIT 99-8

                        CERTIFICATION OF PERIODIC REPORT

I, David E. Meador, Senior Vice President and Chief Financial Officer of
Michigan Consolidated Gas Company (the "Company"), certify, pursuant to Section
906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that to the best
of my knowledge and belief:

(1)            the Annual Report on Form 10-K of the Company for the annual
               period ended December 31, 2002 (the "Report") fully complies with
               the requirements of Section 13(a) or 15(d) of the Securities
               Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2)            the information contained in the Report fairly presents, in all
               material respects, the financial condition and results of
               operations of the Company.

Date: March 20, 2003                        /s/ DAVID E. MEADOR
                                     ------------------------------------
                                              David E. Meador
                                         Senior Vice President and
                                         Chief Financial Officer of
                                     Michigan Consolidated Gas Company